UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, ~~2017~~2018



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)		74-1492779 (I.R.S. Employer Identification No.)

12377 Merit Drive, Suite 1700, Dallas, Texas		~~75251~~
(Address of principal executive offices)		75251 (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 xþ 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 xþ NO o

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



Large accelerated filer	o	~~Accelerated filer~~	x

~~Non-accelerated filer~~	Accelerated filer o
~~(Do not check if a smaller reporting company)~~Non-accelerated filer þ	Smaller reporting company	oþ
Emerging growth company o
		~~Emerging growth company~~	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

The number of shares of common stock, par value $0.001 per share, outstanding as of November ~~3, 2017~~8, 2018 was ~~21,630,873.~~21,595,457.

EXCO RESOURCES, INC.

~~INDEX~~TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	21
	Condensed Consolidated Balance Sheets atas of September 30, ~~2017~~2018 and December 31, ~~2016~~2017	21
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, ~~2017~~2018 and ~~2016~~2017	32
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, ~~2017~~2018 and ~~2016~~2017	43
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 30, ~~2017~~2018 and ~~2016~~2017	54
	Notes to Condensed Consolidated Financial Statements	65

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	5652
Item 4.	Controls and Procedures	5753

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	5753
Item 1A.	Risk Factors	5755
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5956
Item 3.	Defaults Upon Senior Securities	56
Item 6.	Exhibits	6057
	Signatures	6865

Table of Contents

PART I—FINANCIAL INFORMATION


Item 1.	Financial Statements

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS


(in thousands)	September 30, 2017			December 31, 2016			September 30, 2018			December 31, 2017
	(Unaudited)						(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	82,459		$	9,068		$	66,963		$	39,597
Restricted cash	23,379			11,150			7,028			15,271
Accounts receivable, net:
Oil and natural gas	39,457			52,674			74,196			55,692
Joint interest	25,555			25,905			24,665			30,570
Other	2,104			3,813			2,014			1,976
Derivative financial instruments - commodity derivatives	1,512			—			—			1,150
Inventory and other	15,915			8,007
Other current assets							19,630			23,574
Total current assets	190,381			110,617			194,496			167,830
Equity investments	25,373			24,365			4,736			14,181
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	112,935			97,080			148,462			118,652
Proved developed and undeveloped oil and natural gas properties	3,055,258			2,939,923			3,307,331			3,107,566
Accumulated depletion	(2,738,103		)	(2,702,245		)	(2,812,174		)	(2,752,311		)
Oil and natural gas properties, net	430,090			334,758			643,619			473,907
Other property and equipment, net	21,078			23,661
Deferred financing costs, net	—			4,376
Derivative financial instruments - commodity derivatives	97			482
Other property and equipment, net and other non-current assets							38,564			21,274
Goodwill	163,155			163,155			163,155			163,155
Total assets	$	830,174		$	661,414		$	1,044,570		$	840,347
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	60,731		$	54,762		$	56,976		$	68,277
Revenues and royalties payable	132,917			120,845			40,486			207,956
Accrued interest payable	6,097			4,701			829			27,637
Current portion of asset retirement obligations	344			344			600			600
Income taxes payable	—			—
Derivative financial instruments - commodity derivatives	1,401			27,711
Current maturities of long-term debt	1,333,989			50,000			473,364			1,362,500
Total current liabilities	1,535,479			258,363			572,255			1,666,970
Long-term debt	21,388			1,258,538
Deferred income taxes	5,885			2,802			—			4,518
Derivative financial instruments - commodity derivatives	—			464
Derivative financial instruments - common share warrants	14,555			—			—			1,950
Asset retirement obligations and other long-term liabilities	13,233			13,153			24,740			13,108
Liabilities subject to compromise							1,491,625			—
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.001 par value; 260,000,000 authorized shares; 21,670,959 shares issued and 21,631,314 shares outstanding at September 30, 2017; 18,915,952 shares issued and 18,876,307 shares outstanding at December 31, 2016	22			19
Common shares, par value $0.001, 260,000,000 shares authorized; 21,635,102 shares issued and 21,595,457 shares outstanding at September 30, 2018; 21,670,186 shares issued and 21,630,541 shares outstanding at December 31, 2017							22			22
Additional paid-in capital	3,539,498			3,538,080			3,541,192			3,539,422
Accumulated deficit	(4,292,254		)	(4,402,373		)	(4,577,632		)	(4,378,011		)
Treasury shares, at cost; 39,645 shares at September 30, 2017 and December 31, 2016	(7,632		)	(7,632		)
Treasury shares, at cost; 39,645 shares at September 30, 2018 and December 31, 2017							(7,632		)	(7,632		)
Total shareholders’ equity	(760,366		)	(871,906		)	(1,044,050		)	(846,199		)
Total liabilities and shareholders’ equity	$	830,174		$	661,414		$	1,044,570		$	840,347

See accompanying notes.

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

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)	2017			2016			2017			2016			2018			2017			2018			2017
Revenues:
Oil	$	12,906		$	16,215		$	43,403		$	49,688		$	27,243		$	12,906		$	67,854		$	43,403
Natural gas	48,323			54,647			151,669			127,044			66,297			48,323			203,608			151,669
Purchased natural gas and marketing	5,507			6,324			19,208			15,335			5,031			5,507			15,703			19,208
Total revenues	66,736			77,186			214,280			192,067			98,571			66,736			287,165			214,280
Costs and expenses:
Oil and natural gas operating costs	9,215			8,797			25,928			25,835			13,010			9,215			31,792			25,928
Production and ad valorem taxes	3,044			3,811			9,894			13,308			4,306			3,044			12,383			9,894
Gathering and transportation	28,743			27,979			83,183			79,828			19,213			28,743			60,499			83,183
Purchased natural gas	5,388			6,586			18,193			17,273			3,776			5,388			11,634			18,193
Depletion, depreciation and amortization	13,518			15,910			36,648			63,995			20,613			13,518			60,819			36,648
Impairment of oil and natural gas properties	—			—			—			160,813
Accretion of discount on asset retirement obligations	221			325			648			2,006
Accretion of liabilities													552			221			1,455			648
General and administrative	10,035			10,746			13,056			38,626			6,115			10,035			20,945			13,056
(Gain) loss on Appalachia JV Settlement													240			—			(119,237		)	—
Other operating items	1,714			(1,110		)	3,069			23,936			(375		)	1,714			(1,382		)	3,069
Total costs and expenses	71,878			73,044			190,619			425,620			67,450			71,878			78,908			190,619
Operating income (loss)	(5,142		)	4,142			23,661			(233,553		)	31,121			(5,142		)	208,257			23,661
Other income (expense):
Interest expense, net	(32,888		)	(16,997		)	(75,320		)	(54,186		)	(8,993		)	(32,888		)	(25,981		)	(75,320		)
Gain (loss) on derivative financial instruments - commodity derivatives	860			8,209			22,934			(11,632		)	—			860			(615		)	22,934
Gain on derivative financial instruments - common share warrants	18,286			—			146,585			—
Gain (loss) on restructuring and extinguishment of debt	—			57,421			(6,380		)	119,374
Gain (loss) on derivative financial instruments - common share warrants													(287		)	18,286			1,428			146,585
Loss on restructuring and extinguishment of debt													—			—			—			(6,380		)
Other income	25			12			4			37			12			25			50			4
Equity income (loss)	354			(823		)	1,009			(8,824		)
Equity income													—			354			179			1,009
Reorganization items, net													(18,169		)	—			(387,457		)	—
Total other income (expense)	(13,363		)	47,822			88,832			44,769			(27,437		)	(13,363		)	(412,396		)	88,832
Income (loss) before income taxes	(18,505		)	51,964			112,493			(188,784		)	3,684			(18,505		)	(204,139		)	112,493
Income tax expense	319			1,028			2,374			1,775
Income tax expense (benefit)													—			319			(4,518		)	2,374
Net income (loss)	$	(18,824	)	$	50,936		$	110,119		$	(190,559	)	$	3,684		$	(18,824	)	$	(199,621	)	$	110,119
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(0.81	)	$	2.73		$	5.35		$	(10.24	)	$	0.17		$	(0.81	)	$	(9.19	)	$	5.35
Weighted average common shares outstanding	23,319			18,670			20,599			18,612			21,616			23,319			21,710			20,599
Diluted:
Net income (loss)	$	(0.81	)	$	2.72		$	5.35		$	(10.24	)	$	0.17		$	(0.81	)	$	(9.19	)	$	5.35
Weighted average common shares and common share equivalents outstanding	23,319			18,749			20,599			18,612			21,616			23,319			21,710			20,599

See accompanying notes.

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2018			2017
Operating Activities:
Net income (loss)	$	110,119		$	(190,559	)	$	(199,621	)	$	110,119
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Deferred income tax expense	3,083			1,775
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income tax expense (benefit)							(4,518		)	3,083
Depletion, depreciation and amortization	36,648			63,995			60,819			36,648
Equity-based compensation	(11,207		)	14,558			1,455			(11,207		)
Accretion of discount on asset retirement obligations	648			2,006
Impairment of oil and natural gas properties	—			160,813
(Gain) loss from equity investments	(1,009		)	8,824
Accretion of liabilities							1,455			648
Income from equity investments							(179		)	(1,009		)
(Gain) loss on derivative financial instruments - commodity derivatives	(22,934		)	11,632			615			(22,934		)
Cash receipts (payments) of commodity derivative financial instruments	(4,967		)	38,097			535			(4,967		)
Gain on derivative financial instruments - common share warrants	(146,585		)	—			(1,428		)	(146,585		)
Amortization of deferred financing costs and discount on debt issuance	18,744			7,250			4,166			18,744
Gain on Appalachia JV Settlement							(119,237		)	—
Non-cash and non-operating reorganization items, net							342,525			—
Loss on restructuring and extinguishment of debt							—			6,380
Paid in-kind interest expense							(21,078		)	38,386
Other non-operating items	2,019			24,068			(2,773		)	2,019
(Gain) loss on restructuring and extinguishment of debt	6,380			(119,374		)
Paid in-kind interest expense	38,386			—
Effect of changes in:
Restricted cash with related party	—			2,100
Accounts receivable	13,183			(12,752		)	(6,105		)	13,183
Other current assets	(6,210		)	(1,207		)	5,847			(6,210		)
Accounts payable and other liabilities	14,809			(14,966		)	47,058			14,809
Net cash provided by (used in) operating activities	51,107			(3,740		)
Net cash provided by operating activities							109,536			51,107
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(91,009		)	(70,455		)	(130,138		)	(91,009		)
Property acquisitions	(24,665		)	—			14,832			(24,665		)
Proceeds from disposition of property and equipment	25			11,242			—			25
Restricted cash	(12,229		)	686
Net changes in amounts due to joint ventures	(9,498		)	2,377			—			(9,498		)
Other							950			—
Net cash used in investing activities	(137,376		)	(56,150		)	(114,356		)	(125,147		)
Financing Activities:
Borrowings under DIP Credit Agreement							156,406			—
Borrowings under EXCO Resources Credit Agreement	163,401			390,897			—			163,401
Repayments under EXCO Resources Credit Agreement	(265,592		)	(243,797		)	(126,401		)	(265,592		)
Proceeds received from issuance of 1.5 Lien Notes, net	295,530			—			—			295,530
Payments on Exchange Term Loan	(11,602		)	(38,056		)
Repurchases of senior unsecured notes	—			(53,298		)
Payments on Second Lien Term Loans							—			(11,602		)
Debt financing costs and other	(22,077		)	(4,569		)	(6,062		)	(22,077		)
Net cash provided by financing activities	159,660			51,177			23,943			159,660
Net increase (decrease) in cash	73,391			(8,713		)
Cash at beginning of period	9,068			12,247
Cash at end of period	$	82,459		$	3,534
Net increase in cash, cash equivalents and restricted cash							19,123			85,620
Cash, cash equivalents and restricted cash at beginning of period							54,868			20,218
Cash, cash equivalents and restricted cash at end of period							$	73,991		$	105,838

Supplemental Cash Flow Information:
Cash interest payments	$	23,072		$	51,975		$	32,401		$	23,072
Income tax payments	—			—			—			—
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	$	852		$	432		$	315		$	852
Capitalized interest	4,627			3,939			2,193			4,627
Net assets acquired on Appalachia JV Settlement, excluding cash and cash equivalents							114,028			—

See accompanying notes.

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


	Common shares				Treasury shares					Additional paid-in capital				Accumulated deficit				Total shareholders’ equity				Common shares				Treasury shares					Additional paid-in capital			Accumulated deficit			Total shareholders’ equity
(in thousands)	Shares		Amount		Shares		Amount							Accumulated deficit			Shares					Amount			Shares	Amount					Additional paid-in capital			Accumulated deficit			Total shareholders’ equity
Balance at December 31, 2015	18,920		$	19	(40	)	$	(7,632	)	Additional paid-in capital		$	3,522,410			$	(4,177,120	Total shareholders’ equity	)		$	(662,323	)
Issuance of common shares	16		—		—		—			—				—				—
Equity-based compensation	—		—		—		—			15,240				—				15,240
Restricted shares issued, net of cancellations	(56	)	—		—		—			—				—				—
Common share dividends	—		—		—		—			—				45				45
Net loss	—		—		—		—			—				(190,559		)		(190,559		)
Balance at September 30, 2016	18,880		$	19	(40	)	$	(7,632	)	$	3,537,650			$	(4,367,634	)		$	(837,597	)
Balance at December 31, 2016	18,916		$	19	(40	)	$	(7,632	)	$	3,538,080			$	(4,402,373	)		$	(871,906	)		18,916		$	19	(40	)	$	(7,632	)	$	3,538,080		$	(4,402,373	)	$	(871,906	)
Issuance of common shares	2,746		3		—		—			11,395				—				11,398				2,746		3		—		—			11,395			—			11,398
Equity-based compensation	—		—		—		—			(9,977		)		—				(9,977		)		—		—		—		—			(9,977		)	—			(9,977		)
Restricted shares issued, net of cancellations	9		—		—		—			—				—				—				9		—		—		—			—			—			—
Net income	—		—		—		—			—				110,119				110,119				—		—		—		—			—			110,119			110,119
Balance at September 30, 2017	21,671		$	22	(40	)	$	(7,632	)	$	3,539,498			$	(4,292,254	)		$	(760,366	)		21,671		$	22	(40	)	$	(7,632	)	$	3,539,498		$	(4,292,254	)	$	(760,366	)

Balance at December 31, 2017																						21,670		$	22	(40	)	$	(7,632	)	$	3,539,422		$	(4,378,011	)	$	(846,199	)
Equity-based compensation																						—		—		—		—			1,770			—			1,770
Restricted shares issued, net of cancellations																						(35	)	—		—		—			—			—			—
Net loss																						—		—		—		—			—			(199,621		)	(199,621		)
Balance at September 30, 2018																						21,635		$	22	(40	)	$	(7,632	)	$	3,541,192		$	(4,577,632	)	$	(1,044,050	)

See accompanying notes.

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

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,” the “Company,” “we,” ~~“us,”~~“our” and ~~“our”~~“us” are to EXCO Resources, Inc. and its consolidated subsidiaries.

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

•East Texas and North Louisiana

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

•South Texas

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

•Appalachia

The Appalachia region is primarily comprised of our Marcellus shale assets. We ~~have~~had a joint venture with Shell covering our Marcellus shale and other assets in the Appalachian region (“Appalachia ~~region ("Appalachia JV"~~JV”). EXCO and Shell each ~~own~~owned an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the Appalachia ~~JV's~~JV’s properties. The remaining 0.5% working interest is held by ~~a jointly owned operating~~an entity ~~("OPCO")~~ that operates the Appalachia ~~JV's properties. We own~~JV’s properties (“OPCO”), which was previously jointly owned by EXCO and Shell. On February 27, 2018, we closed a ~~50%~~settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region (“Appalachia JV Settlement”). As a result of the Appalachia JV Settlement, we acquired Shell’s interests in the Appalachia JV and OPCO. See further discussion of this transaction in “Note 3. Acquisitions, divestitures and other significant events”.

The accompanying Condensed Consolidated Balance Sheets as of September 30, ~~2017~~2018 and December 31, ~~2016,~~2017, Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~2017 are for EXCO and its consolidated subsidiaries. The unaudited Condensed Consolidated Financial Statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States ~~("GAAP"~~(“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"~~(“SEC”) for interim financial statements and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO at as of September 30, ~~2017~~2018 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~~EXCO’s Annual Report on Form 10-K for the year ended December 31, ~~2016,~~2017, filed with the SEC on March ~~16,~~ 15, 2018 (“2017 ~~("2016~~ Form ~~10-K"~~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.

~~Reverse share split~~

Chapter 11 Cases and Going Concern Assessment

On ~~June 2, 2017, we~~January 15, 2018 (“Petition Date”), the Company and certain of its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing, LP and Raider Marketing GP, LLC (collectively, the “Filing Subsidiaries” and, together with the Company, the “Debtors”), filed a certificate of amendment to our Amended and Restated Certificate of Formation to reduce the number of authorized common shares from 780,000,000 to 260,000,000 and effect a 1-for-15 reverse share split. The reverse share split became effective after the market closed on June 12, 2017. The par valuevoluntary petitions for relief under Chapter 11 of the ~~common shares remained unchanged at $0.001 per share, which required retrospective reclassification from common shares~~Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Court”). The cases are being jointly administered under the caption In Re EXCO Resources, Inc., Case No. 18-30155 (MI) (“Chapter 11 Cases”). The Court granted all of the first day motions filed by the Debtors that were designed primarily to additional paid-in capital within the shareholders' equity section of our consolidated balance sheets. Shareholders' equity and all share data, including treasury shares, and per share data presented herein have been retrospectively adjusted to reflectminimize the impact of the ~~decrease~~Chapter 11 Cases on their operations, customers and employees. The Debtors continue to operate their businesses as “debtors in ~~authorized shares~~possession” under the jurisdiction of the Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Court. The Debtors expect to continue operations without interruption during the pendency of the Chapter 11 Cases.

For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to risks and uncertainties associated with Chapter 11 Cases. As a result of these risks and uncertainties, our assets, liabilities, shareholders’ equity, officers and/or directors could be significantly different following the conclusion of the Chapter 11 Cases, and the ~~reverse share split,~~description of our operations, properties and capital plans included in this quarterly report on Form 10-Q may not accurately reflect our operations, properties and capital plans following the conclusion of the Chapter 11 Cases.

The outcome of the Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and creditors. The significant risks and uncertainties related to our liquidity and the Chapter 11 Cases raise substantial doubt about our ability to continue as ~~appropriate.~~

~~Going Concern Assessment~~

a going concern. We define liquidity as cash and restricted cash plus the unused borrowing base under the debtor-in-possession credit agreement (“Liquidity”). 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. We define liquidity as cash and restricted cash plus the unused borrowing base under our credit agreement ("Liquidity").

~~Background~~

On March 15, 2017, we closed a series of transactions including the issuance of $300.0 million in aggregate principal amount of senior secured 1.5 lien notes due March 20, 2022 ("1.5 Lien Notes"), the exchange of $682.8 million in aggregate principal amount of our senior secured second lien term loans due October 26, 2020 ("Second Lien Term Loans") for a like amount of senior 1.75 lien term loans due October 26, 2020 ("1.75 Lien Term Loans," and such exchange, the "Second Lien Term Loan Exchange") and the issuance of warrants to purchase our common shares. The terms of the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allow for interest payments in cash, common shares or additional indebtedness (such interest payments in common shares or additional indebtedness, "PIK Payments"), subject to certain restrictions and limitations as discussed below. See further discussion of these transactions as part of "Note 8. Debt".

On June 20, 2017, we paid interest on the 1.75 Lien Term Loans in common shares, which resulted in the issuance of 2,745,754 common shares ("PIK Shares"). On September 20, 2017, we paid $17.0 million and $26.2 million of interest on the 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, through the issuance of additional 1.5 Lien Notes and 1.75 Lien Term Loans.

Our Liquidity is currently significantly constrained. As of September 30, 2017, our Liquidity was $105.8 million and the principal amount of our outstanding indebtedness was $1.4 billion. During the nine months ended September 30, 2017, our cash flows used in investing activities exceeded our cash flows from operating activities by $86.3 million. We expect cash flows used in investing activities to continue to exceed cash flows from operating activities during the remainder of 2017 and future periods. Our Liquidity is not expected to be sufficient to fund this cash flow deficit and conduct our business operations unless we are able to restructure our current obligations under our existing outstanding debt and other contractual obligations and address near-term liquidity needs. The significant risks to our Liquidity and ability to continue as a going concern are described below.

~~No further availability of credit under EXCO Resources Credit Agreement~~

During the third quarter of 2017, we borrowed substantially all of our remaining unused commitments under our revolving credit agreement ("EXCO Resources Credit Agreement"), and, as of September 30, 2017, we had $126.4 million of outstanding indebtedness and $23.6 million of outstanding letters of credit under the EXCO Resources Credit Agreement. As a result, we had no availability remaining under the EXCO Resources Credit Agreement, including letters of credit, as of September 30, 2017. 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. The redetermination of the borrowing base scheduled for November 2017 is currently in process. 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 the redetermination.

~~Compliance with debt covenants~~

The EXCO Resources Credit Agreement requires that our ratio of aggregate revolving credit exposure to consolidated EBITDAX ("Aggregate Revolving Credit Exposure Ratio") cannot exceed 1.2 to 1.0 as of the end of any fiscal quarter. As of September 30, 2017, our Aggregate Revolving Credit Exposure Ratio exceeded the allowed maximum of 1.2 to 1.0. In anticipation of the potential default, on September 29, 2017, we obtained a limited one-time waiver from the lenders under the

EXCO Resources Credit agreement waiving an event of default as a result of a failure to comply with the Aggregate Revolving Credit Exposure Ratio as of September 30, 2017. We believe it is probable that we will not be in compliance with the Aggregate Revolving Credit Exposure Ratio as of December 31, 2017.

The EXCO Resources Credit Agreement also requires that our cash (as defined in the agreement) plus unused commitments under the EXCO Resources Credit Agreement cannot be less than (i) $50.0 million as of the end of a fiscal month and (ii) $70.0 million as of the end of a fiscal quarter ("Minimum Liquidity Test"). It is probable that we will not be in compliance with the Minimum Liquidity Test for the twelve-month period following the date of these unaudited Condensed Consolidated Financial Statements and may not be able to comply with this covenant as early as of the end of the fourth quarter of 2017. In addition, the EXCO Resources Credit Agreement requires that our ratio of consolidated EBITDAX to consolidated interest expense ("Interest Coverage Ratio") exceeds a minimum of 1.75 to 1.0 for the fiscal quarter ending September 30, 2017 and 2.0 to 1.0 for fiscal quarters thereafter. The definition of consolidated interest expense utilized in the Interest Coverage Ratio excludes PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans. The consolidated EBITDAX and consolidated interest expense utilized in this calculation are annualized beginning with the fiscal quarter ending September 30, 2017. Therefore, we believe that our ability to make interest payments in common shares is essential to maintain compliance with the Interest Coverage Ratio, and as described below, we are currently limited from making future PIK Payments in our common shares.

If we deliver to our lenders an audit report prepared by our auditors with respect to the financial statements for the fiscal year ended December 31, 2017 that includes an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern, then it will be an event of default under each of the EXCO Resources Credit Agreement, 1.5 Lien Notes, and 1.75 Lien Term Loans. These defaults would also result in a default under the indenture governing our senior unsecured notes due September 15, 2018 ("2018 Notes") and our senior unsecured notes due April 15, 2022 ("2022 Notes"). We may not be able to eliminate the substantial doubt concerning our ability to continue as a going concern or obtain waivers with respect to this obligation from our lenders. If the substantial doubt about our ability to continue as a going concern remains at the date we deliver our financial statements for the fiscal year ended December 31, 2017, we would experience an event of default under such agreements.

If we are unable to comply with any of the covenants under the EXCO Resources Credit Agreement, there will be an event of default, and our indebtedness under the EXCO Resources Credit Agreement will be accelerated and become immediately due and payable. This would result in an event of default under the indenture governing the 1.5 Lien Notes, the credit agreement governing the 1.75 Lien Term Loans and the indenture governing the 2018 Notes and 2022 Notes. If this occurs and our indebtedness is accelerated and becomes immediately due and payable, our Liquidity would not be sufficient to pay such indebtedness.

~~Limitations on ability to pay interest on 1.5 Lien Notes and 1.75 Lien Term Loans~~

The principal purpose of issuing the 1.5 Lien Notes and Second Lien Term Loan Exchange was to alleviate our substantial cash interest payment burden and improve our Liquidity. Our initial expectation was to make PIK Payments in common shares on the 1.5 Lien Notes and the 1.75 Lien Term Loans throughout the remainder of 2017 and 2018. However, under our Registration Rights Agreement with the holders of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans ("Registration Rights Agreement"), our ability to make PIK Payments in common shares is subject to a resale registration statement related to the common shares issued as PIK Payments and all of the shares underlying the warrants issued in connection with the 1.5 Lien Notes and 1.75 Lien Term Loans being declared effective by the SEC by October 11, 2017 ("Resale Registration Statement"). We did not anticipate the Resale Registration Statement would be declared effective as of October 11, 2017, and, as such, we provided a notice of a delay of effectiveness for the Resale Registration Statement to the holders of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans, as permitted under the Registration Rights Agreement, extending the requirement for the Resale Registration Statement to be declared effective to no later than December 8, 2017. As of the date of the filing of this Quarterly Report on Form 10-Q, the Resale Registration Statement has not been declared effective and there is no assurance we will be able to satisfy this condition.

Even if the Resale Registration Statement is declared effective, the terms of the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans prohibit the issuance of common shares as PIK Payments if it would result in a beneficial owner, directly or indirectly, owning more than 50% of our outstanding common shares. Our common share price has been, and continues to be, volatile and has significantly decreased during 2017. If our common share price remains at the current levels or continues to decrease, we will have to issue a greater number of common shares to make PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans. This could prevent us from being able to pay interest in common shares due to the 50% ownership limitation. In addition, we may elect not to make PIK Payments because such issuances would contribute to an ownership change under Section 382 of the Internal Revenue Code that could limit our ability

~~to use our net operating loss carryovers (“NOLs”) to reduce future taxable income. As of September 30, 2017, we had estimated NOLs of $2.4 billion.~~

The amount of PIK Payments made in additional 1.5 Lien Notes or 1.75 Lien Term Loans is subject to incurrence covenants within our debt agreements that limit our aggregate secured indebtedness to $1.2 billion. This amount is reduced dollar-for-dollar to the extent that we incur any additional secured indebtedness, including PIK Payments in additional indebtedness. Our ability to make future PIK Payments in additional indebtedness is limited to $6.9 million. Our next quarterly interest payment of approximately $26.9 million, based on the PIK interest rate of 15.0% on the 1.75 Lien Term Loans, is scheduled to occur on December 20, 2017, and is required to be paid in-kind pursuant to the terms of the indenture governing the 1.5 Lien Notes. Furthermore, the agreement governing the 1.75 Lien Term Loans restricts our ability to pay interest in cash, unless we have liquidity, on a pro forma basis, of at least $175.0 million.

As a result of the foregoing, unless we amend our debt agreements or obtain a waiver or other forbearance from certain lenders, we will not be able to make our next interest payment on the 1.75 Lien Term Loans on December 20, 2017. If we cannot make scheduled payments on our debt, we will be in default and holders of our outstanding notes and loans could declare all outstanding principal and interest to be due and payable, the lenders under the EXCO Resources Credit Agreement could terminate their commitments to loan money, and our secured lenders could foreclose against the assets securing their borrowings. Any event of default may cause a default or accelerate our obligations with respect to unsecured indebtedness, including our 2018 Notes and 2022 Notes, which could adversely affect our business, financial condition and results of operations.

~~Near-term debt maturities~~

The maturity date of the EXCO Resources Credit Agreement is July 31, 2018, and our 2018 Notes are due September 15, 2018. As of September 30, 2017, there was approximately $126.4 million aggregate principal amount of indebtedness outstanding, excluding letters of credit, under the EXCO Resources Credit Agreement and approximately $131.6 million aggregate principal amount of indebtedness outstanding under the 2018 Notes. There is no assurance that the maturity date of the EXCO Resources Credit Agreement will be extended or that we will be able to refinance the debt outstanding under the EXCO Resources Credit Agreement on terms that are satisfactory to us, or at all. If we repay the 2018 Notes in full in cash at maturity in September 2018, there will be an event of default under the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans, which would result in an event of default under all of our other debt agreements. In addition, the covenants in the EXCO Resources Credit Agreement limit cash paid for repurchases, exchanges, redemptions or acquisitions of the 2018 Notes and 2022 Notes to $75.0 million; provided further that we shall have, after giving pro forma effect to any such transaction, unused commitments under the EXCO Resources Credit Agreement plus unrestricted cash equal to or greater than $100.0 million. The covenants in the 1.5 Lien Notes and 1.75 Lien Term Loans limit cash paid for repurchases, exchanges, redemptions or acquisitions of the 2018 Notes and 2022 Notes not to exceed $25.0 million. However we may repurchase, exchange, redeem or acquire additional 2018 Notes and 2022 Notes for an amount not to exceed an additional $70.0 million, thereafter, provided that we have liquidity (as defined in the agreement) of at least $200.0 million. Our Liquidity is not expected to be sufficient to repay the outstanding indebtedness due in 2018.

~~Other factors~~

Our Liquidity and compliance with debt covenants may be impacted by the outcome of certain litigation. As described in "Item 3. Legal Proceedings" in our 2016 Form 10-K, we are currently in litigation with Enterprise Products Operating LLC ("Enterprise") and Acadian Gas Pipeline System ("Acadian") in which Enterprise and Acadian filed a suit claiming that we improperly terminated certain sales and transportation contracts with them. If we are unable to satisfactorily resolve our litigation with Enterprise and Acadian and we are required to pay a judgment, any such payment could adversely affect our ability to pay the principal and interest on our outstanding debt. Furthermore, we expect to have a shortfall under a minimum volume commitment for gathering services in the East Texas and North Louisiana regions for the twelve-month period ending November 30, 2017. As of September 30, 2017, we accrued $19.5 million in "Revenues and royalties payable" in our Condensed Consolidated Balance Sheet related to this shortfall and the payment is due within 90 days of the end of the twelve-month period ending November 30, 2017. The payment of this shortfall is expected to have a significant impact on our Liquidity.

~~Management's plans~~

On September 7, 2017, we announced that our Board of Directors has delegated authority to the Audit Committee of the Board of Directors ("Audit Committee") to explore strategic alternatives to strengthen our balance sheet and maximize the value of the Company, which may include, but is not limited to, seeking a comprehensive out-of-court restructuring or reorganization under Chapter 11 of the U.S. Bankruptcy Code. Our plans may include obtaining additional financing or relief from debt holders to support operations throughout the restructuring process, delevering our capital structure, and reducing the

financial burden of certain gathering, transportation and other commercial contracts. At the direction of the Audit Committee, we have retained PJT Partners LP as financial advisors and Alvarez & Marsal North America, LLC as restructuring advisors. We continue to retain Kirkland & Ellis LLP as our legal advisor to assist the Audit Committee and management team with the restructuring process. We are actively engaged in negotiations with our stakeholders to evaluate the feasibility of a consensual in-court or out-of-court restructuring.

If we are unable to restructure our current obligations under our existing outstanding debt and address near-term liquidity needs, we will be forced to seek relief under the U.S. Bankruptcy Code. This may include: (i) pursuing a plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code; (ii) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of our assets and a subsequent liquidation of the remaining assets in a bankruptcy case; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks. In addition, our creditors may file an involuntary petition for bankruptcy against us. In any bankruptcy proceeding, holders of our common shares may receive little or no consideration.

~~Assessment of ability to continue as a going concern~~

Our ability to continue as a going concern is dependent on many factors, including, among other things, sufficient Liquidity to conduct our business operations, our ability to comply with the covenants in our existing debt agreements, our ability to cure any defaults that occur under our debt agreements or to obtain waivers with respect to any such defaults, and our ability to pay, retire, amend, replace or refinance our indebtedness as defaults occur or as interest and principal payments come due. These factors raise substantial doubt about our ability to continue as a going concern.

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.

Chapter 11 filing impact on creditors and shareholders

The Debtors filed schedules and statements with the Court setting forth, among other things, the assets and liabilities of each of the Debtors, subject to the assumptions filed in connection therewith. These schedules and statements are subject to further amendment or modification during the Chapter 11 Cases. Certain holders of pre-petition claims that are not governmental units were required to file proofs of claim by April 15, 2018. The deadline for governmental units to file proofs of claim was September 4, 2018. Differences between amounts scheduled by the Debtors and claims by creditors are being investigated and will be reconciled and resolved to within an immaterial amount in connection with the claims resolution process. In light of the number of creditors with filed or scheduled claims, the claims resolution process may take considerable time to complete and likely will continue after the Debtors emerge from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be presently asserted.

Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition and post-petition liabilities owed to creditors must be satisfied in full before the holders of our existing common shares are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery for creditors and shareholders, if any, will not be determined until confirmation and implementation of a plan of reorganization. The outcome of the Chapter 11 Cases remains uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors or shareholders may receive.

Automatic stay

Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial and administrative actions against the Debtors as well as efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on or otherwise exercise rights or remedies with respect to a pre-petition claim are stayed.

Impact on indebtedness

As of the Petition Date, we had approximately $1.4 billion in principal amount of indebtedness, including approximately: (i) $126.4 million outstanding under our previous revolving credit agreement (“EXCO Resources Credit Agreement”), (ii) $317.0 million outstanding under our senior secured 1.5 lien notes due March 20, 2022 (“1.5 Lien Notes”), (iii) $708.9 million outstanding under our senior secured 1.75 lien term loans due October 26, 2020 (“1.75 Lien Term Loans”), (iv) $17.2 million outstanding under our senior secured second lien term loans due October 26, 2020 (“Second Lien Term Loans”), (v) $131.6 million outstanding under our senior unsecured notes due September 15, 2018 (“2018 Notes”), and (vi) $70.2 million outstanding under our senior unsecured notes due April 15, 2022 (“2022 Notes”). The commencement of the Chapter 11 Cases described above constituted an event of default that accelerated our obligations under the following debt instruments:

EXCO Resources Credit Agreement;

1.5 Lien Notes;

1.75 Lien Term Loans;

2018 Notes; and

2022 Notes.

These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code. As a result of the Chapter 11 Cases, the Court may limit post-petition interest on debt that may be under-secured or unsecured.

On January 22, 2018, we closed a debtor-in-possession credit agreement (“DIP Credit Agreement”) with lenders including affiliates of Fairfax Financial Holdings Limited (“Fairfax”), Bluescape Resources Company LLC (“Bluescape”) and JPMorgan Chase Bank, N.A. (collectively the “DIP Lenders”). The DIP Credit Agreement includes a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million (“Revolver A Facility”) and a senior secured debtor-in-possession revolving credit facility in an aggregate principal amount of $125.0 million (“Revolver B Facility”, and together with the Revolver A Facility, the “DIP Facilities”). Proceeds from the DIP Facilities were used to repay all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 Cases. As of September 30, 2018, we had $156.4 million in outstanding indebtedness and $81.6 million of available borrowing capacity under the DIP Facilities. See further discussion of the DIP Credit Agreement in “Note 8. Debt”. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes.

Restrictions on trading of our equity securities to protect our use of net operating losses

The Court has entered a final order pursuant to Sections 362(a)(3) and 541 of the Bankruptcy Code enabling the Company and the Filing Subsidiaries to avoid limitations on the use of our income tax net operating loss carryforwards (“NOLs”) and certain other tax attributes by imposing certain notice procedures and transfer restrictions on the trading of our equity securities. In general, the order applies to any person that, directly or indirectly, beneficially owns (or would beneficially own as a result of a proposed transfer) at least 4.5% of our outstanding common shares (“Substantial Shareholder”), and requires that each Substantial Shareholder file with the Court and serve us with notice of such status. Under the order, prior to any proposed acquisition or disposition of equity securities that would result in an increase or decrease in the amount of our equity securities owned by a Substantial Shareholder, or that would result in a person or entity becoming a Substantial Shareholder, such person or entity is required to file with the Court and notify us of such acquisition or disposition. We have the right to seek an injunction from the Court to prevent certain acquisitions or sales of our common shares if the acquisition or sale would pose a material risk of adversely affecting our ability to utilize such tax attributes.

Executory contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a breach as of the Petition Date of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against the Debtors for damages caused by such rejection. The assumption of an executory contract or unexpired lease generally requires the Debtors to cure existing monetary or other defaults under such executory contract or unexpired lease and provide adequate assurance of future performance thereunder. Any description of the treatment of an executory contract or unexpired lease with the Company or any of the Filing Subsidiaries, including any description of the obligations under any such executory contract or unexpired lease, is qualified by and subject to any rights they have with respect to executory contracts and unexpired leases under the Bankruptcy Code.

During March 2018, the Court approved the rejection of the following executory contracts:

Firm transportation agreements with Acadian Gas Pipeline System, which required us to transport 325,000 Mmbtu per day on the Acadian Gas Pipeline System or pay reservation charges through October, 31, 2025;

Natural gas sales agreements with Enterprise Products Operating LLC (“Enterprise”), which required us to sell 75,000 Mmbtu per day of natural gas to Enterprise or incur certain costs through October 31, 2025;

Firm transportation agreements with Regency Intrastate Gas Systems LLC, which required us to either transport 237,500 Mmbtu per day of natural gas or pay reservation charges through January 31, 2020;

Marketing agreement with a subsidiary of Chesapeake Energy Corporation (“Chesapeake”), which required us to allow Chesapeake to purchase natural gas from certain wells in North Louisiana through 2021; and

Natural gas sales agreements with Shell, which required us to sell 100,000 Mmbtu per day of natural gas to Shell or incur certain costs through November 30, 2020.

On March 1, 2018, the Debtors filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018. The motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP and Raider Marketing, LP commenced an adversary proceeding (Adv. Proc. No. 18-03096) against Azure to establish that the minimum volume commitment agreement is severable from the base gathering agreement between the parties. The Debtors and the contract counterparties each filed various dispositive motions that were heard by the Court on August 9, 2018. The parties have engaged in settlement discussions related to this matter; however, there can be no assurance the parties will be able to reach an agreement. Any settlement reached between the parties would have to be approved by the Court. As of September 30, 2018, we have accrued $27.6 million related to the minimum volume commitment as “Liabilities subject to compromise” on our Condensed Consolidated Balance Sheet.

On August 9, 2018, the Court approved the rejection of the office lease for our corporate headquarters in Dallas, Texas. We subsequently entered into a new lease for a reduced amount of square footage in the same office building with a term through December 31, 2022.

Plan of Reorganization

On October 1, 2018, the Debtors filed a Settlement Joint Chapter 11 Plan of Reorganization (the “Plan”) and related Disclosure Statement with the Court. As is customary in bankruptcy proceedings, the Debtors subsequently filed amendments to the Plan and related Disclosure Statement with the Court. The Plan does not currently contemplate the divestiture of any of the Company’s assets. The restructuring transactions contemplated by the Plan include the following key elements:

Holders of the DIP Credit Agreement will receive payment in full in cash with proceeds from a new revolving credit facility (“Exit Facility”);

Holders of the 1.5 Lien Notes will receive payment in full in cash (without payment of any premium or “make-whole”) with the proceeds from a new second lien debt instrument;

Holders of the 1.75 Lien Term Loans will receive 82 percent of the equity in the reorganized Company and 82 percent of the interests in a claims trust that will hold certain litigation claims (“Claims Trust”);

Holders of the Second Lien Term Loans, 2018 Notes, 2022 Notes and allowed general unsecured claims (other than “Convenience Claims” as defined below or those creditors that elect to be treated as holding Convenience Claims, and claims against Raider Marketing, LP or Raider Marketing GP, LLC) will receive, collectively, (i) 18 percent of

the equity in the reorganized Company, (ii) $15.4 million in cash, and (iii) 18 percent of the interests in the Claims Trust;

Holders of allowed claims greater than $0 but less than or equal to $405,000 (“Convenience Claims”), along with any holder of an allowed general unsecured claim who elects to be treated as a holder of an allowed Convenience Claim, will receive a pro rata share of $5.0 million in cash;

Holders of claims against Raider Marketing, LP or Raider Marketing GP, LLC shall not receive a distribution and claims will be deemed canceled, discharged, released and extinguished;

Holders of existing equity interests in EXCO shall not receive a distribution and the equity interests will be deemed cancelled, discharged, released and extinguished; and

The carriers of directors’ and officers’ liability insurance coverage related to the Debtors agreed to pay $13.4 million (“D&O Proceeds”) in exchange for full and final settlement of potential claims and causes of action against current and former directors and officers.

The Debtors shall fund distributions under the Plan with: (i) cash on hand; (ii) the Exit Facility; (iii) a new second lien debt instrument; (iv) the equity in the reorganized Company; and, (v) the D&O Proceeds.

We currently believe the Plan would allow us to preserve our tax attributes upon emergence if we are eligible for an exception in Section 382(l)(5) of the Internal Revenue Code. See further discussion of Section 382 of the Internal Revenue Code and the impact of the Plan on our tax attributes in “Note 10. Income taxes”.

On November 5, 2018, the Court authorized us to solicit acceptances of the Plan and approved the Disclosure Statement and other related solicitation materials and procedures necessary to approve the Plan. We are currently in the process of soliciting votes with respect to the Plan. The Plan is subject to acceptance by certain holders of claims against the Debtors and to confirmation by the Court. The Plan will be accepted by a class of claims entitled to vote if at least one-half in number and two-thirds in dollar amount of claims actually voting in the class have voted to accept the Plan. Under certain circumstances set forth in the Bankruptcy Code, the Court may confirm the Plan even if it has not been accepted by all impaired classes of claims and equity interests if the Debtors demonstrate, among other things, that (i) no class junior to the rejecting class is receiving or retaining property under the plan and (ii) no class of claims or interests senior to the rejecting class is being paid more than in full. A hearing to consider confirmation of the Plan is scheduled to be held on December 10, 2018 in the Court (“Confirmation Hearing”). If the Plan is ultimately confirmed by the Court, the Debtors will emerge from bankruptcy pursuant to the terms of the Plan.

Accounting during bankruptcy

We have applied Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), in the preparation of these Condensed Consolidated Financial Statements. For periods subsequent to the Chapter 11 filings, ASC 852 requires the financial statements to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred during the bankruptcy proceedings, including losses related to executory contracts that have been approved for rejection by the Court, and adjustments to the carrying value of certain indebtedness are recorded as “Reorganization items, net” on the Condensed Consolidated Statement of Operations. In addition, pre-petition obligations that may be impacted by the Chapter 11 process have been classified on the Condensed Consolidated Balance Sheet as of September 30, 2018 as “Liabilities subject to compromise.”

Liabilities subject to compromise

The accompanying Condensed Consolidated Balance Sheet as of September 30, 2018 includes amounts classified as liabilities subject to compromise, which represent liabilities that are anticipated to be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate of known or potential obligations to be resolved in connection with the Chapter 11 Cases, and may differ from actual future settlement amounts paid. Differences between liabilities estimated and claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.

Liabilities subject to compromise include amounts related to the rejection of various executory contracts and unexpired leases. Additional amounts may be included in liabilities subject to compromise in future periods if additional executory contracts or unexpired leases are rejected. Conversely, to the extent that executory contracts or unexpired leases are not rejected and are instead assumed, liabilities associated therewith would constitute post-petition liabilities which will be satisfied in full under a plan of reorganization. The nature of certain potential claims arising under the Debtors’ executory contracts and

unexpired leases has not been determined at this time, and therefore, such claims are not reasonably estimable at this time and may be material.

The following table summarizes the components of liabilities subject to compromise included on the Condensed Consolidated Balance Sheet as of September 30, 2018:



(in thousands)	September 30, 2018
Current maturities of long-term debt	$	927,917
Accrued interest payable	34,281
Accounts payable, accrued expenses and other liabilities	110,656
Liabilities related to rejected executory contracts	418,771
Liabilities subject to compromise	$	1,491,625

As of September 30, 2018, the principal and accrued interest associated with the DIP Credit Agreement and 1.5 Lien Notes were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Court and our current estimates of the recoverability of claims related to these instruments.

Reorganization items, net

We have incurred significant expenses associated with the Chapter 11 process, primarily (i) the acceleration of deferred financing costs, debt discounts and deferred reductions in carrying value associated with debt instruments previously accounted for as a troubled debt restructuring pursuant to ASC 470-60, Troubled Debt Restructuring by Debtors, (ii) adjustments for estimated allowable claims related to executory contracts approved for rejection by the Court, and (iii) legal and professional fees incurred subsequent to the Petition Date related to the restructuring process. These costs, which are being expensed as incurred, significantly impact our results of operations. The following table summarizes the components included in “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the three and nine months ended September 30, 2018:



(in thousands)	Three Months Ended September 30, 2018		Nine Months Ended September 30, 2018
Legal and professional fees	$	15,184	$	44,766
Deferred financing costs, debt discounts and deferred reductions in carrying value	—		30,509
Rejection of executory contracts	2,985		312,182
Reorganization items, net	$	18,169	$	387,457

Interest expense

We have discontinued recording interest on debt instruments classified as liabilities subject to compromise as of the Petition Date. The contractual interest on liabilities subject to compromise not reflected in the Condensed Consolidated Statement of Operations was approximately $75.6 million, representing interest expense from the Petition Date through September 30, 2018. The cash interest rate of 12.5% was utilized in the determination of contractual interest expense that would have been incurred under the 1.75 Lien Term Loans for the period subsequent to the Petition Date.

2.Significant accounting policies

We consider significant accounting policies to be those related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our ~~2016~~2017 Form 10-K. In addition, see further discussion of our application of ASC 852 as a result of the Chapter 11 Cases in “Note 1. Organization and basis of presentation”.

~~Goodwill~~Recent accounting pronouncements

In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). The main difference between the current requirement under GAAP and ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires that a lessee recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term (other than leases that meet the definition of a short-term lease). The liability will be equal to the present value of lease payments. The asset will be based on the liability, subject to adjustment, such as for initial direct costs. For income statement purposes, the FASB retained a dual model, requiring leases to be classified as either operating or finance leases. Operating leases will result in straight-line expense (similar to current operating leases) while finance leases will result in a front-loaded expense pattern (similar to current capital leases). Classification will be based on criteria that are largely similar to those applied in current lease accounting. For lessors, the guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. ASU 2016-02 is effective for annual and interim periods beginning after December 15, 2018 and early adoption is permitted.

In January 2018, the FASB issued further guidance on the new lease standard in ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 provides a practical expedient to exclude existing or expired land easements from the evaluation of leases under ASU 2016-02 if the easements were not previously accounted for as leases under the current guidance. In July 2018, the FASB issued additional guidance on the accounting for leases in ASU No. 2018-10, Codification Improvements to Topic 842, Leases, and ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). ASU 2016-02 was initially required to be adopted using a modified retrospective transition, which would require application of the new guidance at the beginning of the earliest comparative period presented. The guidance in ASU 2018-11 provides companies with another transition method that allows entities to recognize a cumulative-effect adjustment to the opening balance of retained earnings as of the date of adoption. Under this method, previously presented years’ financial positions and results would not be adjusted. The new guidance also provides lessors with a practical expedient, by class of underlying asset, to not separate non-lease components from the associated lease component if (1) the non-lease components would otherwise be accounted for under the new revenue recognition standard, (2) both the timing and pattern of transfer are the same for the non-lease components and associated lease component, and (3) if accounted for separately, the lease component would be classified as an operating lease. We ~~perform~~are currently assessing the potential impact of ASU 2016-02 and related clarifying updates and expect they will have an ~~impairment test for goodwill at least annually or more frequently as impairment indicators arise. Our impairment test is typically performed~~impact on our consolidated financial condition and results of operations upon adoption. We are currently unable to quantify the impact the standard will have on our consolidated financial condition and results of operations.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) (“ASU 2016-18”). The amendments in this update require that a statement of cash flows explain the change during the ~~fourth quarter; however, we performed~~period in total cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. ASU 2016-18 is effective for annual and interim periods beginning after December 15, 2017 and early adoption is permitted. We adopted ASU 2016-18 in the first quarter of 2018 utilizing retrospective application. The adoption resulted in an ~~impairment test as~~increase in reported investing cash flows of ~~June 30, 2017 and~~$12.2 million for the nine months ended September 30, 2017 ~~due~~with a corresponding adjustment to the reported end of period cash balances.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a ~~significant decline~~Business (“ASU 2017-01”). ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. Under ASU 2017-01, an entity must first determine whether substantially all of ~~EXCO's market capitalization. As a result of our testing,~~ the fair value of ~~our~~the gross assets acquired is concentrated in a single identifiable asset or a group of similar assets. If this threshold is met, the set is not a business. If this threshold is not met, the entity then evaluates whether the set meets the requirement that a business ~~exceeded~~includes, at a minimum, an input and a substantive process that together significantly contribute to the ~~carrying value~~ability to create outputs. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. We adopted ASU 2017-01 in the first quarter of ~~net assets~~2018 and ~~we did not record an impairment charge~~

will apply the guidance of ASU 2017-01 prospectively to future asset acquisitions, including the acquisitions as part of the Appalachia JV Settlement during the ~~second or third~~first quarter of ~~2017.~~2018.

~~Recent accounting pronouncements~~

In July 2017, the ~~Financial Accounting Standards Board ("FASB")~~FASB issued ~~Accounting Standards Update ("ASU")~~ASU No. 2017-11, Earnings Per Share (Topic 260), Distinguishing Liabilities from Equity (Topic 480), Derivatives and Hedging (Topic 815): I. Accounting for Certain Financial Instruments with Down Round Features, II. Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception(" (“ASU ~~2017-11"~~2017-11”). ASU 2017-11 revises the guidance for instruments with down round features in Subtopic 815-40, Derivatives and Hedging - Contracts in Entity’s Own Equity, which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. An entity is still is required to determine whether instruments would be classified in equity under the guidance in Subtopic 815-40 in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. Our 2017 Warrants as(as defined in ~~"Note~~“Note 7. Derivative ~~Financial Instruments",~~financial instruments”) are required to be classified as liabilities under the current guidance due to their down round features. The amendments in Part I are required to be applied retrospectively to outstanding financial instruments with down round features. ASU 2017-11 is effective for annual and interim periods beginning after December 15, 2018, and early adoption is permitted, including adoption in an interim period. We are currently assessing the impact of ASU 2017-11; however, we believe that it ~~may~~could have ~~a significant~~an impact on our consolidated financial condition and results of operations if we determine the 2017 Warrants qualify for equity classification. ~~During~~However, we believe it is highly likely that our existing common shares as well as the ~~nine months ended September 30,~~ 2017 ~~we recorded a gain~~Warrants will be canceled at the conclusion of ~~$146.6 million on the~~our Chapter 11 Cases.

~~revaluation of the 2017 Warrants on the Condensed Consolidated Statements of Operations and a liability of $14.6 million on the Condensed Consolidated Balance Sheet as of September 30, 2017.~~

In ~~May 2017,~~March 2018, the FASB issued ASU No. ~~2017-09, Compensation -~~ 2018-05, Income Taxes (Topic 740): Amendments to SEC paragraphs pursuant to SEC Staff Accounting Bulletin No. 118 (“ASU 2018-05”). The amendments in this update add various SEC paragraphs pursuant to the issuance of SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”). SAB 118 directs taxpayers to consider the implications of the Tax Cuts and Jobs Act (“Tax Act”) as provisional when it does not have the necessary information available, prepared, or analyzed in reasonable detail to complete its accounting for the change in the tax law. SAB 118 provides a one-year measurement period from a registrant’s reporting period that includes the Tax Act’s enactment date to allow the registrant sufficient time to obtain, prepare and analyze information to complete the required accounting under ASC 740. As described in the 2017 Form 10-K, we reflected the impact of the changes in rates on our deferred tax assets and liabilities at December 31, 2017, as we are required to reflect the change in the period in which the law is enacted. We are still analyzing certain aspects of the Tax Act, which could potentially affect the measurement of our income tax balances and future income tax expense or benefit. The ultimate impact of the Tax Act may differ from the estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Tax Act.

In June 2018, the FASB issued ASU No. 2018-07, Compensation—Stock Compensation (Topic 718): ~~Scope~~Improvements to Nonemployee Share-Based Payment Accounting (“ASU 2018-07”). The amendments in this update expand the scope of ~~Modification Accounting~~ ("Topic 718 to include share-based payment transactions for acquiring goods or services from nonemployees. An entity should apply the requirements of Topic 718 to nonemployee awards except in certain circumstances. ASU ~~2017-09")~~2018-07 clarifies that Topic 718 applies to all share-based payment transactions in which a grantor acquires goods or services to be consumed in a grantor’s operations unless the transaction effectively provides financing to the grantor or are awarded under a contract accounted for under Topic 606 (as defined below). ASU ~~2017-09 provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. ASU 2017-09~~2018-07 is effective for ~~annual~~fiscal years and interim periods within those fiscal years beginning after December 15, ~~2017, and early adoption is permitted.~~2018. The amendments require that adjustments required upon application of the update be made through a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption. We ~~adopted ASU 2017-09 in the current period;~~have historically awarded share-based compensation to nonemployees; however, we do not currently have any outstanding share-based awards to nonemployees. Therefore, we do not believe the adoption of ASU ~~2017-09 did not~~2018-07 will have an impact on our consolidated financial condition and results of ~~operations. We will apply~~operations unless share-based payments are issued to nonemployees in the ~~guidance in ASU 2017-09 in future periods, if applicable.~~future.

In ~~August 2016,~~July 2018, the FASB issued ASU No. ~~2016-15, Statement of Cash Flows (Topic 230):~~ ~~Classification of Certain Cash Receipts and Cash Payments~~ ("2018-09, Codification Improvements (“ASU ~~2016-15"~~2018-09”). ~~ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows.~~ The amendments in ~~ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement~~this update include changes to clarify and make other incremental improvements to GAAP under the FASB’s perpetual project to address suggestions from stakeholders. The amendments in this update affect a wide variety of ~~zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation~~topics and apply to all reporting entities within the ~~effective interest rate~~scope of the ~~borrowing, contingent consideration payments made after a business combination, proceeds from~~affected accounting guidance. The transition and effective date guidance is based on the ~~settlement~~facts and circumstances of ~~insurance claims, proceeds from~~each amendment. A number of the ~~settlement~~amendments do not require transition guidance and are effective as of ~~corporate-owned life insurance policies and distributions received from equity method investees. ASU 2016-15 is~~the issuance of the update while many of the updates that have transition guidance are effective for annual ~~and interim~~ periods beginning after December 15, ~~2017,~~2018. For amendments relating to issued but not effective guidance, the effective date of these amendments follows that of the originally issued update. We are currently assessing the potential impact of the many amendments within ASU 2018-09 and ~~early adoption is permitted. We early adopted ASU 2016-15 and~~are currently unable to quantify the impact, if any, the standard will apply the new guidance, if applicable, in future periods. We elected to apply the cumulative earnings approach to classify distributions received from equity method investees. The adoption of ASU 2016-15 did not have ~~an impact~~ on our ~~current~~ consolidated financial condition and results of operations.

Revenue from Contracts with Customers (Topic 606)

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) ("(“ASU ~~2014-09"~~2014-09”). The FASB and the International Accounting Standards Board ~~("IASB")~~ jointly issued this comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under currently applicable guidance, including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. During 2016, theThe FASB issued ~~four~~ additional ASUs that primarily clarified the implementation guidance on principal versus agent considerations, performance obligations and licensing, collectability, presentation of sales taxes and other similar taxes collected from customers, and non-cash consideration. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2017 and permits the use of either the retrospective or cumulative effect transition method.

We ~~are currently assessing the impact of~~adopted ASU 2014-09 and ~~the~~ related updates ~~and clarifications and are performing a review~~in the first quarter of ~~the new guidance. We intend to adopt ASU 2014-09 and the related updates for the interim and annual periods beginning after December 15, 2017 and we expect to adopt the new standard using~~2018 based on the modified retrospective method of adoption. ~~We are evaluating the new guidance and performing detailed analysis~~The adoption of ~~our contracts. We are currently unable to quantify the impact the standard will have on our consolidated financial condition and results of operations; however, we do not believe~~ this standard ~~will~~did not have ~~a material~~an impact ~~if any,~~ on our consolidated financial condition and results of operations. ~~However,~~We have implemented processes to ensure new contracts are reviewed for the ~~adoption~~appropriate accounting treatment and to generate the disclosures required under the new standard.

Overview of marketing arrangements

We produce oil and natural gas. We do not refine or process the oil or natural gas we produce. We sell the majority of the ~~standard will require~~oil we produce under contracts using market sensitive pricing. The majority of our oil contracts are based on NYMEX pricing, which is typically calculated as the average of the daily closing prices of oil to be delivered one month in the future. We also sell a portion of our oil at F.O.B. field prices posted by the principal purchaser of oil where our producing properties are located. Our sales contracts are of a type common within the industry, and we usually negotiate a separate contract for each area. Generally, we sell our oil to purchasers and refiners near the areas of our producing properties.

We sell the majority of our natural gas under individually negotiated gas purchase contracts using market sensitive pricing. Our sales contracts vary in length from spot market sales of a single day to term agreements that may extend for a month or more. Our natural gas customers primarily include natural gas marketing companies. The natural gas purchase contracts define the terms and conditions unique to each of these sales. The price received for natural gas sold on the spot market varies daily, reflecting changing market conditions.

Revenue recognition under ASC 606

We use the sales method of accounting for oil and natural gas revenues. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes primarily on company-measured volume readings. We then adjust our oil and natural gas sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. Historically, these differences have been immaterial. Natural gas imbalances at September 30, 2018 and December 31, 2017 were not significant.

We generally sell oil and natural gas under two types of agreements that are common in our industry. Both types of agreements include transportation charges. We evaluate whether we are the principal or the agent in each transaction. The first type of agreement is a net-back arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation costs incurred by the purchaser. The purchaser takes custody, title and risk of loss of the oil or natural gas at the wellhead. In this case, we record revenue when the control transfers to the purchaser at the wellhead based on the price received, net of the transportation costs.

Under the second type of agreement, we sell oil or natural gas at a specific delivery point, pay transportation to a third-party and receive proceeds from the purchaser with no transportation deduction. The purchaser takes custody, title, and risk of loss of the oil or natural gas at the specific delivery point. In this case, we are deemed to be the principal and the ultimate third-party purchaser is deemed to be the customer. We recognize revenue when control transfers to the purchaser at the specific delivery point based on the price received from the purchaser. The costs that we ~~provide expanded disclosures~~incur to transport the oil or natural gas are recorded as gathering and transportation expenses. As such, our computed realized prices include revenues that are recognized under two separate bases.

Raider Marketing, LP (“Raider”) is a wholly owned subsidiary focused on the marketing of oil and natural gas. Raider purchases and resells natural gas from third-party producers, as well as oil and natural gas from operated wells in Texas and Louisiana, and charges a fee for marketing services to certain working interest owners in the related wells. Raider takes custody, title and risk of loss from the third-party producer upon the purchase of natural gas and then sells the natural gas to a

separate third-party purchaser further downstream. The price paid for the purchase of natural gas from the third-party producer is not dependent on the price received from the ultimate purchaser. We are deemed to be the principal in these transactions. As such, third party purchases and sales are reported on a gross basis as “Purchased natural gas” expenses and “Purchased natural gas and marketing” revenues, respectively. The marketing fee charged by Raider to certain working interest owners in our operated wells is reported as “Purchased natural gas and marketing” revenues.

Transaction price allocated to remaining performance obligations

Our sales are short-term in nature with a contract term of one year or less. We have utilized the practical expedient in ASC 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Contract balances

Under our oil and natural gas sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-period performance obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil and natural gas sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. We have internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the three and nine months ended September 30, 2018, revenue recognized in the reporting period related to ~~the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.~~performance obligations satisfied in prior reporting periods was not material.

3.Acquisitions, divestitures and other significant events

~~Termination of South Texas divestiture~~Appalachia JV Settlement

On ~~April 7, 2017,~~January 26, 2018, we ~~entered~~filed a motion in the Court to authorize the entry into a ~~purchase and sale~~settlement agreement with a subsidiary of ~~Venado~~ Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region. The final order related to this settlement was approved on February 22, 2018 and we closed the settlement agreement on February 27, 2018. Under the terms of the Appalachia JV Settlement:

Shell transferred its interests to EXCO in each of BG Production Company (PA), LLC, BG Production Company (WV), LLC, OPCO, and Appalachia Midstream, LLC (“Appalachia Midstream”). On April 20, 2018, BG Production Company (PA), LLC legally changed its name to EXCO Production Company (PA) II, LLC and BG Production Company (WV), LLC legally changed its name to EXCO Production Company (WV) II, LLC;

Shell and EXCO terminated and considered to be fulfilled obligations and liabilities under certain specified agreements related to the Appalachia JV;

EXCO reconveyed its interests in certain leases, representing an interest in 364 net acres, that EXCO had previously acquired from Shell within the area of mutual interest, in exchange for consideration of $0.7 million;

EXCO and Shell mutually released all existing, future, known, and unknown claims for all existing, future, known, and unknown damages and remedies that each party may have against one another arising out of or relating to the joint development agreement, the area of mutual interest, the arbitration, the state court action, and all joint venture dealings among the parties and certain of their affiliates in the Appalachia region, except as expressly provided in the settlement; and

EXCO caused the arbitration and the state court action to be dismissed with prejudice.

The settlement increased our acreage in the Appalachia region by approximately 177,700 net acres, and the production from the additional interests in producing wells acquired was 26 net Mmcfe per day during December 2017. In addition, EXCO now owns 100% of OPCO and Appalachia Midstream subsequent to the settlement. Prior to the settlement, we accounted for our 50% ownership interests in OPCO and Appalachia Midstream as equity method investments. The entities associated with the Appalachia JV Settlement, including EXCO Production Company (PA) II, LLC, EXCO Production Company (WV) II,

LLC, OPCO, and Appalachia Midstream, have not filed for relief under Chapter 11 of the Bankruptcy Code, and the operations of these entities are not expected to be affected by the Chapter 11 Cases.

We accounted for the acquisitions in accordance with FASB ASC 805, Business Combinations. The following table presents a summary of the fair value of assets acquired and liabilities assumed as part of the Appalachia JV Settlement as of the closing date.



(in thousands)	Amount
Assets acquired:
Cash and cash equivalents	$	14,832
Accounts receivable, net	6,493
Other current assets	5,264
Unproved oil and natural gas properties	33,542
Proved developed and undeveloped oil and natural gas properties, net	72,548
Other assets	18,109
Liabilities assumed:
Accounts payable and accrued liabilities	(9,718		)
Asset retirement obligations	(2,315		)
Other long-term liabilities	(9,895		)
Fair value of net assets acquired	$	128,860

The fair value of the assets and liabilities acquired as part of the Appalachia JV Settlement of $128.9 million resulted in a gain of $119.2 million after remeasurement of our previously held equity interest in OPCO and Appalachia Midstream and adjustments to certain balances held by OPCO. As of the closing date, the carrying value of our equity investments in OPCO and Appalachia Midstream was $9.6 million.

We performed a valuation of the assets and liabilities acquired as of the closing date. A summary of the key inputs is as follows:

Working capital - The fair value approximated the carrying value for working capital including cash and cash equivalents, accounts receivable, other current assets, accounts payable and accrued liabilities.

Oil and ~~Gas, LLC ("Venado")~~natural gas properties - The fair value allocated to ~~divest our~~unproved and proved oil and natural gas properties was $33.5 million and ~~surface acreage in South Texas for a total purchase price~~$72.5 million, respectively. The fair value of ~~$300.0 million that was subject to closing conditions and adjustments based on an effective date of January 1, 2017.~~

Pursuant to the terms of the agreement, the closing of the transaction was originally anticipated to occur on June 1, 2017 (the “Original Scheduled Closing Date”), unless certain conditions had not been satisfied or waived on or prior to the Original Scheduled Closing Date. The purchase agreement included conditions to the closing, including seller's representation and warranty regarding all material contracts being in full force and effect be true as of the Original Scheduled Closing Date. On May 31, 2017, Chesapeake Energy Marketing, L.L.C. (“CEML”) purportedly terminated a long-term natural gas sales contract with an expiration of June 30, 2032, between CEML and Raider Marketing, LP (“Raider”), a wholly owned subsidiary of EXCO.

On June 6, 2017, we filed a petition, application for temporary restraining order and temporary injunction against CEML and subsequently added the parent entity, Chesapeake Energy Corporation ("CEC"). In the lawsuit, we assert breach of contract, tortious interference with existing contract, tortious interference with prospective business relations, and declaratory relief that the contract is still in full force and effect. On June 7, 2017, CEML filed to remove the lawsuit to the United States District Court Northern District of Texas. On June 9, 2017, the District Court denied our motion for temporary restraining order. CEC filed a motion to dismiss on the basis of personal jurisdiction, and the motion remains pending.

Due to the purported contract termination, the closing conditions were not anticipated to be satisfied or waived by the Original Scheduled Closing Date. Therefore, we entered into an amendment to extend the Original Scheduled Closing Date to August 15, 2017. The amendment, among other things, provided that the satisfaction of the closing conditions would be deemed satisfied by the reinstatement of the natural gas sales contract or by entry into a new gathering agreement. Because all closing conditions had not been satisfied or waived by August 15, 2017, EXCO and Venado mutually agreed to terminate the purchase and sale agreement, effective as of August 15, 2017. Following the termination, the purchase and sale agreement was void and of no further effect.

~~North Louisiana acquisitions~~

~~During June and August 2017, we closed the acquisitions of certain~~ oil and natural gas properties was determined based on a discounted cash flow model of the estimated reserves. The estimated quantities of reserves utilized assumptions based on our internal geological, engineering and ~~undeveloped acreage in~~financial data. We utilized NYMEX forward strip prices to value the ~~North Louisiana region for $4.6 million~~reserves then applied various discount rates depending on the classification of reserves and ~~$20.1 million, respectively, subject to customary post-closing purchase price adjustments.~~other risk characteristics.

Other assets - The August 2017 acquisition consisted of a purchase price of $13.3 million and preliminary purchase price adjustments of $6.8 million. The total purchase price, including preliminary purchase price adjustments, was primarilyfair value allocated to ~~$5.2~~other assets was $18.1 million, which is primarily comprised of ~~unproved~~natural gas gathering assets held by Appalachia Midstream. The fair value of the natural gas gathering assets was determined based on transaction multiples of peer companies and a discounted cash flow model from our internally generated oil and natural gas reserves for the related properties.

Asset retirement liabilities - The fair value allocated to asset retirement obligations was $2.3 million. These asset retirement obligations represent the present value of the estimated amount to be incurred to plug, abandon and remediate proved producing properties at the end of their productive lives, in accordance with applicable state laws. The fair value was determined based on a discounted cash flow model, which included assumptions of the estimated current abandonment costs, discount rate, inflation rate, and ~~$14.8 million~~timing associated with the incurrence of ~~proved oil and~~these costs.

Firm transportation contract - OPCO holds a contract that requires it to transport a minimum volume of natural gas ~~properties.~~or pay reservation charges. The performance obligations under the contract exceeded the future economic benefit to be received over the life of the contract. We calculated the fair value as the present value of the remaining unused commitments discounted at a rate consistent with market participants. The fair value of the liability was $12.1 million, including the current portion of $2.2 million and the long-term portion of $9.9 million.

Pro forma results of operations - The following table reflects the unaudited pro forma results of operations if the Appalachia JV Settlement had occurred on January 1, 2017:



	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands except for per share data)	2018		2017			2018			2017
Oil and natural gas revenues	$	98,571	$	67,556		$	291,244		$	228,638
Net income (loss) (1)	3,684		(19,295		)	(198,361		)	113,547
Basic earnings (loss) per share	$	0.17	$	(0.83	)	$	(9.14	)	$	5.51
Diluted earnings (loss) per share	$	0.17	$	(0.83	)	$	(9.14	)	$	5.51

(1)

The pro forma results of operations include adjustments for revenues and direct expenses related to the interests acquired as part of the Appalachia JV Settlement. Net income (loss) for the three and nine months ended September 30, 2018 includes the non-cash gains or losses associated with the fair value of net assets acquired and remeasurement of previously held interests in OPCO and Appalachia Midstream.

Related party transactions - As noted previously, prior to the Appalachia JV Settlement, we accounted for our 50% ownership interests in OPCO and Appalachia Midstream as equity method investments. OPCO served as the operator of our wells in the Appalachia JV and we advanced funds to OPCO on an as needed basis. Additionally, there are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. Prior to the closing of the settlement, we had received $1.7 million under these agreements during 2018.

4.Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months ended September 30, ~~2017:~~2018:


(in thousands)
Asset retirement obligations at beginning of period	$	11,289		$	12,017
Activity during the period:
Liabilities incurred during the period	13			—
Revisions in estimated assumptions				(1		)
Liabilities settled during the period	(101		)	(77		)
Adjustment to liability due to acquisitions	17
Adjustment to liability due to acquisitions (1)				2,319
Adjustment to liability due to divestitures				(7		)
Accretion of discount	648			778
Asset retirement obligations at end of period	11,866			15,029
Less current portion	344			600
Long-term portion	$	11,522		$	14,429


(1)	The increase in our asset retirement obligations during the nine months ended September 30, 2018 is primarily due to additional interests in oil and natural gas properties acquired as part of the Appalachia JV Settlement.

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,~~(collectively, the ~~full~~“full cost ~~pool.~~pool”). We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. There were no impairments of unproved properties during the three and nine months ended September 30, ~~2017 or 2016.~~2018 and 2017.

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"~~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. During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. The rejection of these executory contracts has positively impacted the present value of our proved reserves. See further discussion of the rejection of executory contracts in “Note 1. Organization and basis of presentation”.

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

Average spot prices
Oil (per Bbl) Natural gas (per Mmbtu)
September 30, 2017 $ 49.81
$ 3.00
June 30, 2017 48.95
3.01
March 31, 2017 47.61
2.73
December 31, 2016 42.75
2.48



	Average spot prices
	Oil (per Bbl)		Natural gas (per Mmbtu)
September 30, 2018	$	63.54	$	2.91
June 30, 2018	57.68		2.92
March 31, 2018	53.49		3.00
December 31, 2017	51.34		2.98

We did not recognize an impairment to our proved oil and natural gas properties for the three and nine months ended September 30, ~~2017 or for the three months ended September 30, 2016,~~2018 and we recognized impairments to our proved oil and natural gas properties of $160.8 million for nine months ended September 30, 2016. The impairments during 2016 were primarily due to the decline in oil and natural gas prices.2017. The possibility and amount of any future impairments is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves, future capital expenditures and operating costs.

~~Our~~

As of September 30, 2018, our proved undeveloped reserves ~~other than the~~were limited to certain wells expected to be completed during 2018. Our recognition of proved undeveloped reserves ~~associated with certain wells drilled prior~~continues to September 30, 2017, remained reclassified in unproved primarily due to the uncertainty regarding the financing required to develop these reserves. These reserves remained classified as unproved due to our inability to meet the reasonable certainty criteria for recording proved undeveloped reserves, as prescribed under the SEC requirements, asbe affected by the uncertainty regarding our availability of capital required to develop these ~~reserves still existed at September 30, 2017.~~reserves. A significant amount of our proved undeveloped reserves that were previously reclassified to unproved remain economic at current prices, and we may report proved undeveloped reserves in the future ~~filings~~ if we determine we have the financial capability to execute a development plan.

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

6.Earnings (loss) per share

The following table presents the basic and diluted earnings (loss) per share computations, adjusted to give effect to our reverse share split on June 12, 2017, for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~:2017:


	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)	2017			2016		2017		2016			2018		2017			2018			2017
Basic net income (loss) per common share:
Net income (loss)	$	(18,824	)	$	50,936	$	110,119	$	(190,559	)	$	3,684	$	(18,824	)	$	(199,621	)	$	110,119
Weighted average common shares outstanding	23,319			18,670		20,599		18,612			21,616		23,319			21,710			20,599
Net income (loss) per basic common share	$	(0.81	)	$	2.73	$	5.35	$	(10.24	)	$	0.17	$	(0.81	)	$	(9.19	)	$	5.35
Diluted net income (loss) per common share:
Net income (loss)	$	(18,824	)	$	50,936	$	110,119	$	(190,559	)	$	3,684	$	(18,824	)	$	(199,621	)	$	110,119
Weighted average common shares outstanding	23,319			18,670		20,599		18,612			21,616		23,319			21,710			20,599
Dilutive effect of:
Stock options	—			—		—		—
Restricted shares and restricted share units	—			79		—		—			—		—			—			—
Warrants	—			—		—		—
Weighted average common shares and common share equivalents outstanding	23,319			18,749		20,599		18,612			21,616		23,319			21,710			20,599
Net income (loss) per diluted common share	$	(0.81	)	$	2.72	$	5.35	$	(10.24	)	$	0.17	$	(0.81	)	$	(9.19	)	$	5.35

Basic net income (loss) per common share is based on the weighted average number of common shares outstanding during the period. In addition, warrants representing the right to purchase our common shares at an exercise price of $0.01 are included in our weighted average common shares outstanding and used in the computation of our basic net income (loss) per common share.

Diluted net income (loss) per common share for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~2017 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, warrants representing the right to purchase our common shares at an exercise price of $13.95, and for the three and nine months ended September 30, 2017, warrants issued to Energy Strategic Advisory Services LLC ~~("ESAS"~~(“ESAS”), whether exercisable or not. The computation of diluted net income (loss) per share excluded ~~21,723,733~~10,792,583 and ~~5,872,204~~21,723,733 antidilutive share equivalents for the three months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively, and 11,414,989 and 9,951,298 ~~and 5,968,174~~antidilutive common share equivalents for the nine months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively. The antidilutive common share equivalents for the three and nine months ended September 30, 2018 and 2017 primarily related to the warrants representing the right to purchase our common shares at an exercise price of $13.95. ~~The antidilutive common share equivalents for the three and nine months ended September 30, 2016 primarily related to warrants issued to ESAS.~~

7.Derivative financial instruments

Our derivative financial instruments are comprised of commodity derivatives and common share warrants.

The table below ~~outlines~~presents the ~~classification~~effect of ~~our~~ derivative financial instruments on our Condensed Consolidated Balance ~~Sheets and their~~Sheets:



(in thousands)		September 30, 2018			December 31, 2017
Current assets	Derivative financial instruments - commodity derivatives	$	—		$	1,150
Liabilities subject to compromise	Derivative financial instruments - common share warrants	(522		)	—
Long-term liabilities	Derivative financial instruments - common share warrants	—			(1,950		)

The table below presents the effect of derivative financial ~~impact~~instruments on our Condensed Consolidated Statements of Operations.

~~Fair Value of Derivative Financial Instruments~~

(in thousands) September 30, 2017 December 31, 2016
Current assets Derivative financial instruments - commodity derivatives $ 1,512
$ —
Long-term assets Derivative financial instruments - commodity derivatives 97
482
Current liabilities Derivative financial instruments - commodity derivatives (1,401 ) (27,711 )
Long-term liabilities Derivative financial instruments - commodity derivatives —
(464 )
Net commodity derivative financial instruments $ 208
$ (27,693 )

Long-term liabilities Derivative financial instruments - common share warrants $ (14,555 ) $ —



	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands)	2018			2017		2018			2017
Gain (loss) on derivative financial instruments - commodity derivatives	$	—		$	860	$	(615	)	$	22,934
Gain (loss) on derivative financial instruments - common share warrants	(287		)	18,286		1,428			146,585

~~Effect of Derivative Financial Instruments~~

Three Months Ended September 30, Nine Months Ended September 30,
(in thousands) 2017 2016 2017 2016
Gain (loss) on derivative financial instruments - commodity derivatives $ 860
$ 8,209
$ 22,934
$ (11,632 )
Gain on derivative financial instruments - common share warrants 18,286
—
146,585
—

Commodity derivative financial instruments

~~Our primary objective in entering~~

We have historically entered into commodity 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 commodity 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 commodity 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.

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

~~Our oil and natural gas derivative instruments are comprised of the following instruments:~~

~~Swaps: These contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.~~

~~Collars~~: A collar is a combination of options including a sold call and a purchased put. These contracts allow us to participate in the upside of commodity prices to the ceiling of the call option and provide us with downside protection through the put option. If the market price is below the strike price of the purchased put at the time of settlement then the counterparty pays us the excess. If the market price is above the strike price of the sold call at the time of settlement, we pay the counterparty the excess. These transactions were conducted contemporaneously with a single counterparty and resulted in a net cashless transaction.

We place our commodity derivative financial instruments with the financial institutions that are lenders under the EXCO Resources Credit Agreement that we believe have high quality credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our commodity 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 current credit rating and financial condition restrict our ability to enter into certain types of commodity derivative financial instruments and limit the maturity of the contracts with counterparties. We have historically entered into commodity derivative financial instruments with the financial institutions that are lenders under the EXCO Resources Credit Agreement. Therefore, our ability to enter into commodity derivative financial instruments is limited beyond the maturity of the EXCO Resources Credit Agreement in July 2018. As a result, our exposure to commodity price fluctuations will increase in 2018 due to lower oil and natural gas volumes covered by derivative contracts compared to historical levels. 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 commodity derivative financial instruments as of September 30, 2017:~~

(dollars in thousands, except prices) Volume Bbtu/Mbbl Weighted average strike price per Mmbtu/Bbl Fair value at September 30, 2017
Natural gas:
Swaps:
Remainder of 2017 9,200
$ 3.05
$ (3 )
2018 3,650
3.15
351
Collars:
Remainder of 2017 2,760
(59 )
Sold call 3.28

Purchased put 2.87

Total natural gas $ 289
Oil:
Swaps:
Remainder of 2017 46
$ 50.00
$ (81 )
Total oil $ (81 )
Total commodity derivative financial instruments $ 208

At December 31, ~~2016, we had outstanding swap and collar contracts covering 41,950 and 10,950 Bbtu, respectively, of natural gas and~~2017, we had outstanding swap contracts covering ~~183 Mbbls~~3,650 Bbtu of ~~oil.~~

Atnatural gas at a weighted average strike price of $3.15 per Mmbtu. In January 2018, the counterparty to our remaining open swap contracts early terminated the outstanding contracts effective January 31, 2018. We received proceeds of $0.5 million for the settlement of these contracts in February 2018. As of September 30, ~~2017, the average forward NYMEX WTI oil prices per Bbl for the remainder of 2017 were $51.74 and the average forward NYMEX HH natural gas prices per Mmbtu for the remainder of 2017 and calendar year~~ 2018, ~~were $3.05 and $3.05, respectively.~~

~~Our~~we did not have any outstanding commodity derivative financial instruments covered approximately 56% and 60% of production volumes for the three months ended September 30, 2017 and 2016, respectively, and 59% and 55% for the nine months ended September 30, 2017 and 2016, respectively.instruments.

Common share warrants

In connection with the issuance of the 1.5 Lien Notes, on March 15, 2017, we issued warrants to the investors of the 1.5 Lien Notes representing the right to purchase an aggregate of up to 21,505,383 common shares (assuming a cash exercise) at an exercise price of $13.95 per share ("(“Financing ~~Warrants"~~Warrants”), and warrants representing the right to purchase an aggregate of up to 431,433 common shares (assuming a cash exercise) at an exercise price of $0.01 per share (“Commitment Fee Warrants”). In addition, certain exchanging holders of the Second Lien Term Loans received warrants representing the right to purchase an aggregate of up to 1,325,546 common shares (assuming a cash exercise) at an exercise price of $0.01 per share ("(“Amendment Fee ~~Warrants"~~Warrants”, and with the Commitment Fee Warrants and Financing Warrants, collectively referred to as the ~~"2017 Warrants"~~“2017 Warrants”).

~~Subject~~

On January 16, 2018, affiliates of Fairfax, which had previously been identified as a related party, surrendered all of their rights to ~~certain exceptions~~the Commitment Fee, Amendment Fee and ~~limitations,~~Financing Warrants. Their rights under the 2017 Warrants entitled them to purchase in aggregate up to 10,824,376 common shares at $13.95 per share and 1,725,576 common shares at $0.01 per share.

Pursuant to the terms of the 2017 Warrants, the 2017 Warrants may not be exercised, subject to certain exceptions and limitations, if, as a result of such exercise, the holder ~~of such 2017 Warrants~~ or its affiliates would beneficially own, directly or indirectly, more than 50% of our outstanding common shares. Each of the 2017 Warrants has an exercise term of 5 years from May 31, 2017 and, subject to certain exceptions, may be exercised by cash or cashless exercise. The Financing Warrants are subject to an anti-dilution adjustment in the event we issue common shares for consideration less than the market value of our common shares or exercise price of the Financing Warrants, subject to certain adjustments and exceptions. The Commitment Fee Warrants and the Amendment Fee Warrants are subject to an anti-dilution adjustment in the event we issue common shares at a price per share less than $10.50 per share, subject to certain exceptions and adjustments. The 2017 Warrants are accounted for as derivatives in accordance with FASB ~~Accounting Standard Codification ("ASC") Topic~~ASC 815, Derivatives and Hedging, ("(“ASC ~~815"~~815”), and are required to be classified as liabilities due to the types of anti-dilution adjustments.

We record the 2017 Warrants as non-current liabilities at fair value, with the increase or decrease in fair value being recognized in earnings. The 2017 Warrants will be measured at fair value on a recurring basis until the date of exercise or the date of expiration. As a result of the change in the fair value of the 2017 Warrants, we recorded a loss of $0.3 million and a gain $18.3 million during the three months ended September 30, 2018 and 2017, respectively, and gains of ~~$18.3~~$1.4 million and $146.6 million during the nine months ended September 30, 2018 and 2017, respectively, on the revaluation of the warrants, ~~during three and nine months ended September 30, 2017, respectively,~~ in

~~"Gain~~ “Gain (loss) on derivative financial instruments - common share ~~warrants"~~warrants” on the Condensed Consolidated Statements of Operations. The ~~gain was~~gains were primarily due to a decrease in ~~EXCO's~~our share ~~price.~~price and the cancellation of warrants by affiliates of Fairfax.

8.Debt

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

(in thousands) September 30, 2017 December 31, 2016
EXCO Resources Credit Agreement $ 126,401
$ 228,592
1.5 Lien Notes 316,958
—
Unamortized discount on 1.5 Lien Notes (144,928 ) —
1.75 Lien Term Loans 863,097
—
Unamortized discount on 1.75 Lien Term Loans (18,610 ) —
Exchange Term Loan 23,543
590,477
Fairfax Term Loan —
300,000
2018 Notes 131,576
131,576
Unamortized discount on 2018 Notes (305 ) (520 )
2022 Notes 70,169
70,169
Deferred financing costs, net (12,524 ) (11,756 )
Total debt 1,355,377
1,308,538
Current maturities of long-term debt 1,333,989
50,000
Long-term debt $ 21,388
$ 1,258,538



(in thousands)	September 30, 2018		December 31, 2017
DIP Credit Agreement	$	156,406	$	—
EXCO Resources Credit Agreement	—		126,401
1.5 Lien Notes, net of unamortized discount	316,958		176,560
1.75 Lien Term Loans, net of unamortized discount	708,926		845,763
Second Lien Term Loans	17,246		23,543
2018 Notes, net of unamortized discount	131,576		131,345
2022 Notes	70,169		70,169
Deferred financing costs, net	—		(11,281		)
Total debt, net	1,401,281		1,362,500
Less amounts included in liabilities subject to compromise	927,917		—
Current maturities of long-term debt	$	473,364	$	1,362,500

September 30, 2017
(in thousands) Carrying value Deferred reduction in carrying value Unamortized discount/deferred financing costs Principal balance
EXCO Resources Credit Agreement $ 126,401
$ —
$ —
$ 126,401
1.5 Lien Notes 172,030
—
144,928
316,958
1.75 Lien Term Loans 844,487
(154,171 ) 18,610
708,926
Exchange Term Loan 23,543
(6,297 ) —
17,246
2018 Notes 131,271
—
305
131,576
2022 Notes 70,169
—
—
70,169
Deferred financing costs, net (12,524 ) —
12,524
—
Total debt $ 1,355,377
$ (160,468 ) $ 176,367
$ 1,371,276

~~The terms and conditions of our debt obligations are discussed below.~~

~~EXCO Resources Credit Agreement~~

Concurrently with the issuance of the 1.5 Lien Notes and as a condition precedent thereto, on March 15, 2017, we amended the EXCO Resources Credit Agreement to, among other things, permit the issuance of the 1.5 Lien Notes and the exchanges of Second Lien Term Loans, reduce the borrowing base thereunder to $150.0 million and modify certain financial covenants. During the third quarter of 2017, we borrowed substantially all of our remaining unused commitments and had $126.4 million of outstanding indebtedness and $23.6 million of outstanding letters of credit under the EXCO Resources Credit Agreement as of September 30, 2017. As a result, we had no availability remaining under the EXCO Resources Credit Agreement, including letters of credit, as of September 30, 2017. 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. The redetermination of the borrowing base scheduled for November 2017 is currently in process. 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 the redetermination.

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, as amended on September 29, 2017, ranges from London

Interbank Offered Rate ("LIBOR") plus 250 bps to 350 bps (or alternate base rate ("ABR") plus 150 bps to 250 bps), depending on our borrowing base usage. On September 30, 2017, our interest rate was approximately 4.7%.

~~Our financial covenants (as defined in the EXCO Resources Credit Agreement), require that:~~

our cash (as defined in the EXCO Resources Credit Agreement) plus unused commitments under the EXCO Resources Credit Agreement cannot be less than (i) $50.0 million as of the end of a fiscal month and (ii) $70.0 million as of the end of a fiscal quarter;

our Aggregate Revolving Credit Exposure Ratio cannot exceed 1.2 to 1.0 as of the end of any fiscal quarter. Aggregate revolving credit exposure utilized in the Aggregate Revolving Credit Exposure Ratio includes borrowings and letters of credit under the EXCO Resources Credit Agreement; and

our Interest Coverage Ratio cannot be less than 1.75 to 1.0 for the fiscal quarter ending September 30, 2017 and 2.0 to 1.0 for fiscal quarters thereafter. The consolidated EBITDAX and consolidated interest expense utilized in this ratio are based on the most recent fiscal quarter ended multiplied by 4.0 as of September 30, 2017, the most recent two fiscal quarters ended multiplied by 2.0 as of December 31, 2017, ~~the most recent three fiscal quarters ended multiplied by 4/3~~we classified all of our outstanding indebtedness as of March 31, 2018, and the trailing twelve month period for fiscal quarters ending thereafter. The definition of consolidated interest expense includes cash interest payments that are accounted for as reductions in the carrying amount of indebtedness in accordance with FASB ASC 470-60, ~~Troubled Debt Restructuring by Debtors. Consolidated interest expense is limited to payments in cash, and excludes PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans.~~

~~As of September 30, 2017, our Aggregate Revolving Credit Exposure Ratio exceeded the allowed maximum of 1.2 to 1.0. In anticipation of the potential default, on September 29, 2017, we obtained~~ a ~~limited one-time waiver from the lenders under the EXCO Resources Credit agreement waiving an event of default~~current liability as a result of ~~a failure to comply with the Aggregate Revolving Credit Exposure Ratio as~~agreements entered into in anticipation of ~~September 30, 2017. A breach of any covenant under the EXCO Resources Credit Agreement could also cause an event~~events of default under the indenture governing the 1.5 Lien Notes, credit agreement governing the 1.75 Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes. Although an event of default has not yet occurred, FASB ASC Topic 470, ~~Debt, requires~~certain debt to be presented as a current liability if a debtor modifies a covenant in anticipation of a potential default and it is probable the debtor will not be able meet the covenant in future periods. We believe it is probable that we will not be in compliance with the Aggregate Revolving Credit Exposure ratio as of December 31, 2017. Therefore, we have classified the amounts outstanding under the EXCO Resources Credit Agreement,agreements, as well as any outstanding debt with cross-default provisions, ~~as a current liability. See discussion regarding our Liquidity, compliance with debt covenants and ability to continue as a going concern as part of "Note 1. Organization and basis of presentation".~~

~~1.5 Lien Notes~~

On March 15, 2017, we issued an aggregate of $300.0 million of 1.5 Lien Notes due March 20, 2022 to affiliates of Fairfax Financial Holdings Limited ("Fairfax"), Bluescape Resources Company LLC ("Bluescape"), Oaktree Capital Management, LP ("Oaktree"), and an ~~unaffiliated investor.~~event of default under the Second Lien Term Loans. The 1.5 Lien Notes bear interest at a cash interest rate of 8% per annum, or, if we elect to make interest payments on the 1.5 Lien Notes with our common shares or, in certain circumstances, by issuing additional 1.5 Lien Notes, at an interest rate of 11% per annum. Interest is payable bi-annually on March 20 and September 20 of each year, commencing on September 20, 2017. On September 20, 2017 we paid the interest due on the 1.5 Lien Notes in-kind with approximately $17.0 million of aggregate principal amount of 1.5 Lien Notes, resulting in $317.0 million of total aggregate principal amount of 1.5 Lien Notes outstanding as of September 30, 2017.

~~As described in “Note 7. Derivative financial instruments,” in connection with the issuance~~commencement of the ~~1.5 Lien Notes, we also issued the Commitment Fee Warrants and the Financing Warrants. The combined fair value~~Chapter 11 Cases constituted an event of the Commitment Fee Warrants and the Financing Warrants of $148.6 million as of March 15, 2017 and $4.5 million of cash paid to certain investors who elected to receive cash in lieu of Commitment Fee Warrants was recorded as a discount to the 1.5 Lien Notes. The discount and $4.3 million of transaction costs incurred related to the transaction are being amortized to interest expense over the life of the 1.5 Lien Notes. We used the majority of the proceeds from the issuance of the 1.5 Lien Notes to repay the entire amount outstandingdefault that accelerated our obligations under the EXCO Resources Credit Agreement, ~~in March 2017.~~

1.5 Lien Notes, 1.75 Lien Term Loans, ~~and Second Lien Term Loan Exchange~~

During 2015, we closed a 12.5% senior secured second lien term loan with certain affiliates of Fairfax in the aggregate principal amount of $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 $400.0 million (“Exchange Term Loan" and together with the Fairfax Term Loan, "Second Lien Term Loans"). The proceeds from the Exchange Term Loan were used to repurchase a portion of the outstanding 2018 Notes and 2022 ~~Notes~~Notes. These debt instruments provide that as a result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code.

As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in ~~exchange~~the Chapter 11 Cases. These amounts represent our current estimate and may materially differ from actual future settlement amounts paid. This resulted in expenses of $24.4 million for the ~~holders~~acceleration of ~~such notes agreeing to act as lenders~~(i) deferred financing costs, (ii) debt discounts, and (iii) deferred reductions in ~~connection~~carrying value associated with ~~the Exchange Term Loan. The exchange was~~debt instruments previously 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 Loanwhich was ~~adjusted to equal the total undiscounted future cash payments, including interest and principal. All cash payments under the terms of the Exchange Term Loan, whether designated~~classified as ~~interest or as principal amount, reduce the carrying amount and no interest expense is recognized.~~

In connection with the offering of the 1.5 Lien Notes, on March 15, 2017, we completed the Second Lien Term Loan Exchange whereby approximately $682.8 million in aggregate principal amount of the outstanding Second Lien Term Loans, consisting of all of the outstanding indebtedness under the Fairfax Term Loan and approximately $382.8 million in aggregate principal amount of the Exchange Term Loan, were exchanged for approximately $682.8 million in aggregate principal amount of 1.75 Lien Term Loans. As a result of the Second Lien Term Loan Exchange, the Fairfax Term Loan was deemed satisfied and paid in full and was terminated. In addition, by participating in the Second Lien Term Loan Exchange, each exchanging lender was deemed to consent to an amendment to the Second Lien Term Loans that eliminated substantially all of the restrictive covenants and events of default in the agreements governing the Second Lien Term Loans. Following the Second Lien Term Loan Exchange, the Company has approximately $17.2 million in aggregate principal amount of Second Lien Term Loans outstanding, consisting entirely of the remaining portion of the Exchange Term Loan.

The Second Lien Term Loan Exchange was accounted for as a modification of debt, and no gain or loss was recognized on the exchange. As described in “Note 7. Derivative financial instruments,” in connection with the issuance of the 1.75 Lien Term Loans, we also issued the Amendment Fee Warrants. The combined fair value of the Amendment Fee Warrants issued to the lenders of the 1.75 Lien Term Loans on March 15, 2017 of $12.6 million and $8.6 million of cash paid to the lenders who elected to receive cash in lieu of warrants was recorded as a discount to the 1.75 Lien Term Loans, and is being amortized to interest expense over the life of the loans. The transaction costs related to the Second Lien Term Loan Exchange of $6.4 million were recorded in "Gain (loss) on restructuring and extinguishment of debt"“Reorganization items, net” in our Condensed Consolidated ~~Statements~~Statement of Operations for the nine months ended September 30, ~~2017.~~

The 1.75 Lien Term Loans are due on October 26, 2020, bear interest at a cash rate of 12.5% per annum, or, if we elect to pay interest on the 1.75 Lien Term Loans with our common shares or, in certain circumstances, by issuing additional 1.75 Lien Term Loans, at an interest rate of 15.0% per annum. On September 20, 2017 we paid the interest due on the 1.75 Lien Term Loans in-kind with approximately $26.2 million of aggregate principal amount of 1.75 Lien Term Loans, resulting in $708.9 million of total aggregate principal amount of 1.75 Lien Term Loans outstanding as of September 30, 2017.

~~PIK Payments under the 1.5 Lien Notes and the 1.75 Lien Term Loans~~

The indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allow us to make PIK Payments subject to certain restrictions and limitations. See further discussion of the limitations on our ability make PIK Payments in "Note 1. Organization and basis of presentation".

Prior to December 31, 2018, the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allow us to make PIK Payments on the 1.5 Lien Notes and the 1.75 Lien Term Loans in our sole discretion, subject to certain limitations. After December 31, 2018, the amount of PIK Payments we are permitted to make will depend on our level of liquidity, which, for the purposes of 1.5 Lien Notes and 1.75 Lien Term Loans, is defined as (i) the sum of (a) our unrestricted cash and cash equivalents and (b) any amounts available to be borrowed under the EXCO Resources Credit Agreement (to the extent then available) less (ii) the face amount of any letters of credit outstanding under the EXCO Resources Credit Agreement. The PIK Payment percentage after December 31, 2018 decreases linearly from as much as 100% to 0% as the level of liquidity increases from less than $150.0 million to greater than $225.0 million, respectively. However, we are currently restricted from paying interest in our common shares, and our ability to make future PIK Payments in additional indebtedness is limited to $6.9 million. See "Note 1. Organization and basis of presentation" for further discussion.

On June 20, 2017, we issued a total of 2,745,754 PIK Shares in lieu of an approximate $23.0 million cash interest payment under the 1.75 Lien Term Loans. The number of PIK Shares issued was calculated based on the interest rate for PIK Payments of 15.0%, which resulted in a value of $27.6 million for the interest payment. The price of the Company's common shares for determining PIK Shares was based on the trailing 20-day volume weighted average price calculated as of the end of the three trading days prior to February 28, 2017.

On September 20, 2017, we paid approximately $17.0 million and $26.2 million of PIK Payments under the 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, through the issuance of additional 1.5 Lien Notes and 1.75 Lien Term Loans.

~~Covenants, events of default and other material provisions under the 1.5 Lien Notes and the 1.75 Lien Term Loans~~

The 1.5 Lien Notes and 1.75 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 Shell. The 1.5 Lien Notes and 1.75 Lien Term Loans are secured by second priority liens and third priority liens, respectively, on substantially all of EXCO’s assets and the assets of such guarantors. Subject to certain exceptions, the covenants under the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans 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 we conduct;~~

~~enter into transactions with affiliates;~~

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

~~incur liens; and~~

~~enter into sale/leaseback transactions.~~

In addition, the indenture governing the 1.5 Lien Notes includes restrictions on our ability to incur additional indebtedness, including debt under the EXCO Resources Credit Agreement in excess of $150.0 million, among other things and subject to certain restrictions. The indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans require that net cash proceeds of certain asset sales be used within one year to acquire or develop oil and natural gas properties or we must use2018. As discussed below, the proceeds from the DIP Facilities were used to ~~permanently~~ repay redeem or repurchase a portion of the EXCO Resources Credit Agreement, 1.5 Lien Notes or 1.75 Lien Term Loans. If there is an event of default, we will be required to pay each of the 1.5 Lien Notes and the 1.75 Lien Term Loans in an amount equal to the outstanding principal amount plus an applicable make-whole premium.

In connection with the offering of the 1.5 Lien Notes and the Second Lien Term Loan Exchange, we entered into an amended and restated intercreditor agreement, under which the lenders of the remaining outstanding portion of the Exchange Term Loan agreed to subordinate their security interest in the collateral to the interests of the holders of the 1.5 Lien Notes, the 1.75 Lien Term Loans and the lenders under EXCO Resources Credit Agreement. In addition, the lenders of the 1.75 Lien Term Loans agreed to subordinate their security interest in the collateral to the interests of the holders of the 1.5 Lien Notes and the lendersall obligations under the EXCO Resources Credit Agreement and the ~~holders~~EXCO Resources Credit Agreement was terminated. The financing costs of $6.1 million that were directly attributable to the DIP Credit Agreement were expensed as “Reorganization items, net” in our Condensed Consolidated Statement of Operations for the nine months ended September 30, 2018.

On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We accrued interest on 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes through the Petition Date with no interest accrued subsequent to the filings. The 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes have been reclassified as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet as of September 30, 2018. As of September 30, 2018, the carrying value for each of our debt instruments approximates the principal amount. As of September 30, 2018, the principal and accrued interest associated with the DIP Credit Agreement and 1.5 Lien Notes were not classified as liabilities subject to compromise as a result of the adequate protection approved by the Court and our current estimate of the recoverability of claims related to these debt instruments.

The Plan provides for a reorganization of the Debtors as a going concern with a significant reduction in indebtedness and improved capital structure. See further discussion of the key proposed restructuring elements contemplated in the Plan and the confirmation process in “Note 1. Organization and basis of presentation”. The DIP Credit Agreement is expected to be repaid in full with proceeds from the issuance of the Exit Facility. Furthermore, the 1.5 Lien Notes ~~agreed~~are expected to ~~subordinate their security interest~~be repaid in full in cash (without payment of any premium or “make-whole”) with the ~~collateral~~proceeds from a new second lien debt instrument. We are currently engaged in discussions with financial institutions regarding the potential issuance of the Exit Facility and a new second lien debt instrument. Our ability to consummate the ~~lenders~~Plan is dependent upon our ability to issue the Exit Facility and the new second lien debt instrument. There can be no assurance the exit financing required to consummate the Plan will be available or, if available, offered on acceptable terms.

DIP Credit Agreement

On January 18, 2018, the Court entered into an interim order that authorized us to enter into the DIP Credit Agreement. On January 22, 2018, we closed the DIP Credit Agreement, which includes the Revolver A Facility in an aggregate principal amount of $125.0 million and the Revolver B Facility in an aggregate principal amount of $125.0 million with the DIP Lenders. Hamblin Watsa Investment Counsel Ltd. is the administrative agent (“DIP Agent”) for the DIP Credit Agreement. The proceeds of the DIP Facilities may be used in accordance with the DIP Credit Agreement to (i) repay obligations outstanding under the EXCO Resources Credit ~~Agreement.~~

~~2018 Notes~~

~~The 2018 Notes are guaranteed on~~Agreement, (ii) pay for operating expenses incurred during the Chapter 11 Cases subject to a ~~senior unsecured basis by a majority of EXCO’s subsidiaries, with~~budget provided to the ~~exception of certain non-guarantor subsidiaries and our jointly held equity investments with Shell. Our equity investments, other than OPCO, have been designated as unrestricted subsidiaries~~DIP Lenders under the ~~indenture governing~~DIP Credit Agreement, (iii) pay for certain transaction costs, fees and expenses, and (iv) pay for certain other costs and expenses of administering the ~~2018 Notes.~~

~~During 2015 and 2016, we completed exchanges and a series of open market repurchases~~Chapter 11 Cases. We used approximately $104.0 million of the ~~2018 Notes significantly reducing~~proceeds provided through the ~~aggregate principal amount outstanding. As of September 30, 2017, $131.6 million in principal was~~DIP Facilities to repay all obligations outstanding ~~on the 2018 Notes. Interest accrues at 7.5% per annum and is payable semi-annually in arrears on March 15 and September 15 of each year. The maturity date of the 2018 Notes is September 15, 2018.~~

~~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. During 2015 and 2016, we completed exchanges and a series of open market repurchases of the 2022 Notes significantly reducing the aggregate principal amount outstanding. As of September 30, 2017, $70.2 million in principal was outstanding on the 2022 Notes.

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~~Under the DIP Credit Agreement, approximately $24.0 million of outstanding letters of credit were deemed issued under the ~~same base indenture governing~~Revolver A Facility, and approximately $21.6 million of loans outstanding under the EXCO Resources Agreement were deemed exchanged for loans under the Revolver B Facility.

On February 22, 2018, ~~Notes and~~ the ~~supplemental indenture governing~~Court entered into a final order authorizing entry into the ~~2022 Notes contains similar covenants to those~~DIP Credit Agreement on a final basis. The entry into the final order resulted in the ~~supplemental indenture governing~~termination of the EXCO Resources Credit Agreement. As of September 30, 2018, ~~Notes.~~we had $156.4 million in outstanding indebtedness and $12.0 million of letters of credit outstanding under the DIP Facilities. Our available borrowing capacity under the DIP Facilities was $81.6 million as of September 30, 2018.

~~See discussion regarding~~

All amounts outstanding under the DIP Facilities bear interest at an adjusted LIBOR plus 4.00% per annum. During the continuance of an event of default under the DIP Facilities, the outstanding amounts bear interest at an additional 2.00% per annum above the interest rate otherwise applicable.

The DIP Facilities will mature on the earliest of (a) 12 months from the initial borrowings on January 22, 2018, (b) the effective date of a plan of reorganization in the Chapter 11 Cases, or (c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIP Facilities following an event of default. The DIP Credit Agreement provided us with an option to extend the maturity of the DIP Facilities to the date that is 18 months from the initial borrowing date if certain conditions are met. These conditions included a requirement to file a plan of reorganization with the Court no later than July 1, 2018. We did not file a plan of reorganization with the Court prior to July 1, 2018; therefore, an extension of the DIP Facilities beyond the original maturity date would require a waiver or consent from the DIP Lenders. Borrowings under the DIP Credit Agreement are subject to an initial borrowing base of $250.0 million. The initial borrowing base redetermination will occur on or about January 1, 2019. Thereafter, the borrowing base will be subject to adjustment semi-annually, on April 1 and October 1 of each year based upon the value of our ~~Liquidity, compliance with debt covenants~~oil and ~~ability to continue as a going concern~~gas reserves. The DIP Lenders have considerable discretion in setting our borrowing base as part of ~~"Note 1. Organization and basis~~the redetermination process. However, we may elect to redetermine the borrowing base to an amount equal to two-thirds of ~~presentation".~~the net present value, discounted at nine percent, of our proved developed reserves.

The DIP Lenders and the DIP Agent, subject to the Carve-Out (as defined below), at all times: (i) are entitled to joint and several super-priority administrative expense claim status in the Chapter 11 Cases; (ii) have a first priority lien on substantially all of our assets; (iii) have a junior lien on any of our assets subject to a valid, perfected and non-avoidable lien as of the Petition Date, other than such liens securing the obligations under the 1.5 Lien Notes, 1.75 Lien Term Loans and Second Lien Term Loans, and (iv) have a first priority pledge of 100% of the stock and other equity interests in each of our direct and indirect subsidiaries. Our obligations to the DIP Lenders and the liens and super-priority claims are subject in each case to a carve out (“Carve-Out”) that accounts for certain administrative, court and legal fees payable in connection with the Chapter 11 Cases.

The DIP Credit Agreement contains certain financial covenants, including, but not limited to:

our cash (as defined in the DIP Credit Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than $20.0 million; and

aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the DIP Agent. The testing period is based on the immediately preceding four-week period and is measured every two weeks. The 13-week forecast is provided to the DIP Agent on a monthly basis and shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the DIP Agent.

As of September 30, 2018, we were in compliance with all of the covenants under the DIP Credit Agreement. The DIP Credit Agreement contains events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases. The DIP Facilities contained

an event of default if we failed to pursue a Court hearing no later than July 1, 2018 to consider the sale of all or substantially all of our assets; however, the final order entered by the Court deemed this requirement to be no longer in force and effect.

9.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"~~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.

During the nine months ended September 30, ~~2017~~2018 and ~~2016~~2017 there were no changes in the fair value level ~~classifications, except that the Exchange Term Loan was reclassified to Level 3.~~classifications.

Fair value of derivative financial instruments

The following table presents a summary of the estimated fair value of our derivative financial instruments as of September 30, ~~2017~~2018 and December 31, ~~2016.~~2017.


	September 30, 2017										As of September 30, 2018
(in thousands)	Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Derivative financial instruments - commodity derivatives	$	—	$	208		$	—	$	208
Liabilities:
Derivative financial instruments - common share warrants	—		(14,555		)	—		(14,555		)	$	—	$	522	$	—	$	522
	December 31, 2016										As of December 31, 2017
(in thousands)	Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets:
Derivative financial instruments - commodity derivatives	$	—	$	(27,693	)	$	—	$	(27,693	)	$	—	$	1,150	$	—	$	1,150
Liabilities:
Derivative financial instruments - common share warrants											—		1,950		—		1,950

Derivative financial instruments - commodity derivatives

We ~~evaluate~~have historically evaluated commodity derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them on a gross basis in our Condensed Consolidated Balance Sheets. Net commodity derivative asset values are determined primarily by quoted NYMEX futures prices, notional volumes and utilization of the counterparties’ credit-adjusted risk-free rate curves and net commodity derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the LIBOR curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

~~The valuation of our commodity price derivatives, represented by oil and natural gas swaps and collar contracts, is discussed below.~~

~~Oil derivatives~~. Our oil derivatives are swap contracts for notional barrels of oil at fixed NYMEX oil index prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for oil index prices, and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

~~Natural gas derivatives~~. Our natural gas derivatives consisted of swap and collar contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap and option contracts. The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for natural gas, (iii) the applicable credit-adjusted risk-free rate curve, as described above,

~~and (iv) the implied rates of volatility inherent in the option contracts. The implied rates of volatility were determined based on the average of historical HH natural gas prices.~~

The fair value of our commodity derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers or sellers.

Derivative financial instruments - common share warrants

The liability attributable to our common share warrants as of the issuance date and the end of each reporting period ~~was~~is measured using the Black-Scholes model based on inputs including our share price, volatility, expected remaining life and the risk-free rate of return. The implied rates of volatility were determined based on historical prices of our common shares over a period consistent with the expected remaining life. Common share warrants are measured at fair value on a recurring basis until the date of exercise or the date of expiration.

See further details on ~~the fair value of~~ our derivative financial instruments in “Note 6.7. Derivative financial instruments”.

Fair value of other financial instruments

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

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

The estimated fair values of our senior notes and term loans are presented below. The estimated fair values of the 2018 Notes and 2022 Notes have been calculated based on quoted prices in active markets. The estimated fair ~~value~~values of the 1.5 Lien Notes and Second Lien Term Loans were calculated based on a model internally prepared by management that lacks significant observable inputs and was classified as Level 3. The 1.75 Lien Term Loans ~~and the Exchange Term Loan have~~has been calculated based on quoted prices obtained from third-party pricing sources that lack significant observable inputs and are classified as Level 3. The 2017 Warrants are considered freestanding financial instruments and are not considered in the determination of the fair value of the 1.5 Lien Notes and 1.75 Lien Term Loans. The estimated fair value of the Exchange Term Loan was calculated based on quoted prices obtained from third-party sources and classified as Level 2 during 2016. During the nine months ended September 30, 2017, we reclassified the fair value of the Exchange Term Loan into Level 3 due to the lack of market activity and significant observable inputs. See ~~"Note~~“Note 8. ~~Debt"~~Debt” for the carrying value and the principal balance of each debt instrument included in the table below.


	September 30, 2017								As of September 30, 2018
(in thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
1.5 Lien Notes	$	—	$	—	$	232,276	$	232,276	$	—	$	—	$	315,790	$	315,790
1.75 Lien Term Loans	—		—		474,980		474,980		—		—		322,561		322,561
Exchange Term Loan	—		—		11,555		11,555
Second Lien Term Loans									—		—		5,260		5,260
2018 Notes	33,210		—		—		33,210		20,394		—		—		20,394
2022 Notes	14,341		—		—		14,341		10,876		—		—		10,876
	December 31, 2016								As of December 31, 2017
(in thousands)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Exchange Term Loan	$	—	$	294,000	$	—	$	294,000
Fairfax Term Loan	—		222,000		—		222,000
1.5 Lien Notes									$	—	$	—	$	232,276	$	232,276
1.75 Lien Term Loans									—		—		372,186		372,186
Second Lien Term Loans									—		—		9,054		9,054
2018 Notes	79,028		—		—		79,028		4,658		—		—		4,658
2022 Notes	35,260		—		—		35,260		2,586		—		—		2,586

10.Income taxes

We ~~have historically evaluated~~evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and ~~applied~~apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. However, due to our annual effective tax rate being highly sensitive to estimates of total ordinary income or loss, we calculated an estimated year-to-date effective tax rate for the nine months ended September 30, 2017. Our annual effective tax rate is highly sensitive to estimates of ordinary income or loss primarily due to significant

permanent differences related to the non-taxable gains or losses on the 2017 Warrants and non-deductible interest on our 1.5 Lien Notes and 1.75 Lien Term Loans.

We have accumulated financial net 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 ~~decreased $95.5~~increased $37.4 million for the nine months ended September 30, ~~2017.~~2018. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately ~~$1.3 billion~~$880.9 million that have fully offset our net deferred tax assets ~~excluding the deferred tax liability for goodwill,~~ as of September 30, ~~2017.~~2018. 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.

The utilization of our NOLs to offset taxable income in future periods may be limited if we undergo an ownership change pursuant to the criteria in Section 382 of the Internal Revenue Code. Generally, an ownership change occurs for Section 382 purposes when the percentage of stock held by one or more five-percent shareholders increases by more than 50 percentage points over the lowest stock ownership held by such shareholders on any testing date within a three-year period. ~~The indenture governing~~See further discussion of restrictions imposed by the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allow us to make PIK Payments in common shares, subject to certain restriction and limitations. Our common share price has been and continues to be volatile, and has significantly decreased during 2017. If our common share price remains at the current levels or continues to decrease, the payment of interest in common sharesCourt on the ~~1.75 Lien Term Loans on December 20, 2017~~trading of our equity securities to protect our use of NOLs in “Note 1. Organization and basis of presentation”. The Internal Revenue Code permits the exclusion of cancellation of debt income from taxable income if the discharge occurs during a Chapter 11 case. If this occurs, the amount of cancellation of debt income would ~~more-likely-than-not cause us~~reduce a company’s tax attributes unless it is offset by NOLs. The NOLs that are available to ~~experience an ownership change pursuant to~~offset cancellation of debt income in a Chapter 11 case are not limited by Section 382 of the Internal Revenue Code. As of September 30, ~~2017,~~2018, we had estimated NOLs of ~~$2.4~~$2.3 billion.

~~11.Related party transactions~~There is an exception to the foregoing annual limitation rules for entities in bankruptcy that generally applies when “qualified creditors” of a debtor corporation receive, in respect of their claims, at least 50 percent of the voting rights and value of the equity of the reorganized debtor pursuant to a confirmed chapter 11 plan (the “382(l)(5) Exception”). Under the 382(l)(5) Exception, a debtor’s NOLs prior to the ownership change are not limited on an annual basis, but, instead, NOL carryforwards will be reduced by the amount of any interest deductions claimed during the three taxable years preceding the effective date of the plan of reorganization, and during the part of the taxable year prior to and including the effective date of the plan of reorganization, in respect of all debt converted into equity in the reorganization. If the 382(l)(5) Exception applies and the reorganized debtors undergo another “ownership change” within two years after the effective date of the plan of reorganization, then the reorganized debtors’ losses prior to the ownership change would effectively be eliminated in their entirety.

~~OPCO~~We currently believe the structure of the Plan would allow us to qualify for the 382(l)(5) Exception. If we are eligible for the 382(l)(5) Exception, we currently anticipate that we would not elect out of its application in order to preserve the Company’s tax attributes. However, our ability to qualify for the 382(l)(5) Exception is subject to further analysis and ~~Appalachia Midstream JV~~depends on our ability to consummate the Plan in substantially the same form as currently set forth, the actions of our creditors and the board of directors of the reorganized Company. Therefore, we cannot provide any assurance regarding the extent of limitations on the Company’s tax attributes upon emergence from bankruptcy.

~~OPCO serves~~On December 22, 2017, the United States enacted the Tax Act which, among other things, lowered the U.S. Federal tax rate from 35% to 21%, repealed the corporate alternative minimum tax, and provided for a refund of previously accrued alternative minimum tax credits. We reflected the impact of this rate on our deferred tax assets and liabilities at December 31, 2017, as it is required to reflect the ~~operator~~change in the period in which the law is enacted. The Tax Act also repealed the corporate alternative minimum tax for tax years beginning after January 1, 2018 and provided that prior alternative minimum tax credits would be refundable. We have credits that are expected to be refunded between 2018 and 2020 as a result of the Tax Act and monetization opportunities under current law in 2017. In addition, the Tax Act limits the amount taxpayers are able to deduct for NOLs generated in taxable years beginning after December 31, 2017 to 80% of the taxpayer’s taxable income. The law also generally repeals all carrybacks for losses generated in taxable years ending after December 31, 2017. However, any NOLs generated in taxable years ending after December 31, 2017 can be carried forward indefinitely. We are still analyzing certain aspects of the Tax Act, which could potentially affect the measurement of our ~~wells~~income tax balances and future income tax expense or benefit. The ultimate impact of the Tax Act may differ from the estimates provided herein, possibly materially, due to additional regulatory guidance, changes in interpretations and assumptions, and other actions as a result of the Appalachia JV and we advance funds to OPCO on an as needed basis. We did not advance any funds to OPCO during three and nine months ended September 30, 2017 or 2016. OPCO may distribute any excess cash equally between us and Shell 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, 2017 and 2016, these transactions included the following:

Three Months Ended September 30, Nine Months Ended September 30,
(in thousands) 2017 2016 2017 2016
Amounts received from OPCO $ 1,562
$ 3,824
$ 4,940
$ 12,586
Tax Act.

As of ~~September 30, 2017 and~~ December 31, ~~2016, the amounts owed were as follows:~~

(in thousands) September 30, 2017 December 31, 2016
Amounts due to EXCO (1) $ 492
$ 618
Amounts due from EXCO (1) 3,389
13,624


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

~~We own~~2017, we recognized a ~~50% interest in~~deferred tax liability of $4.5 million for tax-deductible goodwill. The deferred tax liability related to goodwill was considered to have an ~~entity that owns and operates midstream assets in the Appalachia region ("Appalachia Midstream JV"). On October 12, 2017, EXCO received a $6.0 million cash distribution from Appalachia Midstream JV.~~

~~ESAS~~

We have a services and investment agreement with ESAS, a wholly owned subsidiary of an affiliate of Bluescape. C. John Wilder, Executive Chairman of Bluescape, is the Executive Chairman of our Board of Directors and indirectly controls ESAS. 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 isindefinite life based on ~~EXCO’s common share price achieving certain performance hurdles~~the nature of the underlying asset and could not be offset under GAAP with a deferred tax asset with a definite life, such as ~~compared to a peer group. Amounts due to ESAS are recorded in "Accounts payable and accrued liabilities" in our Condensed Consolidated Balance Sheets.~~NOLs. As a result of ~~EXCO's performance rank, no incentive payment~~

~~was due~~the Tax Act, deferred tax assets resulting from NOLs generated in taxable years subsequent to ~~ESAS for the twelve-month period ending March~~December 31, ~~2017. We did not make~~2017 are considered to have an ~~accrual for the annual incentive payment at September 30, 2017 as a result of EXCO's performance rank.~~

In connection with the services and investment agreement, EXCO issued warrants to ESAS in four tranches representing the right to purchase an aggregate of 5,333,335 common shares ("ESAS Warrants"). 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 ESAS 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. For the three and nine months ended September 30, 2017indefinite life. Therefore, we recognized an income tax benefit of ~~$1.3~~$4.5 million and $14.2 million, respectively, and expense of $0.9 million and $11.8 million, for the three and nine months ended September 30, 2016, respectively, of equity-based compensation related to the ESAS Warrants. The income recorded during ~~the three and nine months ended September 30, 2017 was due to a significant decrease in the fair value of the ESAS Warrants primarily as a result of a decrease in the Company's share price.~~

On September 20, 2017, ESAS received $4.0 million and $1.8 million of PIK Payments in the form of additional 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, resulting in ESAS holding $74.0 million in aggregate principal amount of 1.5 Lien Notes and $49.7 million in aggregate principal amount of 1.75 Lien Term Loans as of September 30, 2017. During the nine months ended September 30, ~~2017, ESAS also received $1.2 million of cash interest payments on~~2018 because we expect to be able to utilize deferred tax assets related to NOLs to offset the ~~Exchange Term Loan and 192,609 of PIK Shares under the 1.75 Lien Term Loans. In addition, ESAS holds Financing Warrants representing the right~~deferred tax liability related to purchase an aggregate of 5,017,922 common shares at an exercise price equal to $13.95 per share. ESAS received a consent fee of $1.6 million in cash for exchanging its interest in the Exchange Term Loan, and a commitment fee of $2.1 million in cash in connection with the issuance of the 1.5 Lien Notes. At September 30, 2017, ESAS was the beneficial owner of approximately 24.1% of our outstanding common shares, including common shares issuable upon the exercise of the 2017 Warrants.goodwill.

As described above, ESAS is a wholly owned subsidiary of an affiliate of Bluescape, and C. John Wilder, the Executive Chairman of Bluescape, is the Executive Chairman of our Board of Directors and indirectly controls ESAS. 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 1.5 Lien Notes, 1.75 Lien Term Loans and our common shares.

~~Fairfax~~

Samuel Mitchell serves as a Managing Director of Hamblin Watsa Investment Counsel Ltd. ("Hamblin Watsa"), the investment manager of Fairfax and certain affiliates thereof. Samuel Mitchell was a member of our Board of Directors until his resignation on September 20, 2017. On September 20, 2017, certain affiliates of Fairfax received $8.5 million and $15.8 million of PIK Payments in the form of additional 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, resulting in Fairfax holding, directly or indirectly, $159.5 million in aggregate principal amount of 1.5 Lien Notes and $427.9 million in aggregate principal amount of 1.75 Lien Term Loans as of September 30, 2017. During the nine months ended September 30, 2017, Fairfax also received $10.6 million of cash interest payments on the Fairfax Term Loan and the Exchange Term Loan and 1,657,330 of PIK Shares under the 1.75 Lien Term Loan. In addition, Fairfax holds Financing Warrants representing the right to purchase an aggregate of 10,824,377 common shares at an exercise price equal to $13.95 per share, Commitment Fee Warrants representing the right to purchase an aggregate of 431,433 common shares at an exercise price equal to $0.01 per share and Amendment Fee Warrants representing the right to purchase an aggregate of 1,294,143 common shares at an exercise price equal to $0.01 per share.

~~Oaktree~~

B. James Ford serves as a Senior Advisor of Oaktree, and was a member of our Board of Directors until his resignation on September 20, 2017. On September 20, 2017, Oaktree received $2.2 million of PIK Payments in the form of additional 1.5 Lien Notes resulting in certain affiliates of Oaktree holding, directly or indirectly, $41.7 million in aggregate principal amount of 1.5 Lien Notes as of September 30, 2017. In addition, certain affiliates of Oaktree hold Financing Warrants representing the right to purchase an aggregate of 2,831,542 common shares at an exercise price equal to $13.95 per share. Oaktree also received a commitment fee of $1.2 million in cash in connection with the issuance of the 1.5 Lien Notes.

~~12.~~11.Condensed consolidating financial statements

As of September 30, ~~2017,~~2018, the majority of EXCO’s subsidiaries were guarantors under the ~~EXCO Resources~~DIP Credit Agreement, the indenture governing the 1.5 Lien Notes, the credit ~~agreement~~agreements governing the 1.75 Lien Term Loans and Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes. All of our unrestricted subsidiaries under the 1.5 Lien Notes, 1.75 Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes are considered non-guarantor subsidiaries.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The DIP Credit Agreement, 1.5 Lien Notes, 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes, 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. Resources and the Guarantor Subsidiaries solely consist of entities that are Debtors in the Chapter 11 Cases, including each of the Filing Subsidiaries. The non-guarantor subsidiaries solely consist of entities that are not included in the Chapter 11 Cases, including OPCO, Appalachia Midstream, EXCO Production Company (PA) II, LLC, EXCO Production Company (WV) II, LLC and certain other entities (referred to as Non-Guarantor Subsidiaries).

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

Resources;

the Guarantor Subsidiaries;

the Non-Guarantor Subsidiaries;

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

EXCO on a consolidated basis.

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

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

As of September 30, ~~2017~~2018


(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	$	94,216		$	(11,757	)	$	—	$	—		$	82,459		$	53,191		$	(9,960	)	$	23,732		$	—		$	66,963
Restricted cash	—			23,379			—		—			23,379			653			6,375			—			—			7,028
Other current assets	16,082			68,461			—		—			84,543			8,100			106,892			5,513			—			120,505
Total current assets	110,298			80,083			—		—			190,381			61,944			103,307			29,245			—			194,496
Equity investments	—			—			25,373		—			25,373			—			—			4,736			—			4,736
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			112,935			—		—			112,935			—			114,920			33,542			—			148,462
Proved developed and undeveloped oil and natural gas properties	333,253			2,722,005			—		—			3,055,258			334,688			2,899,762			72,881			—			3,307,331
Accumulated depletion	(330,776		)	(2,407,327		)	—		—			(2,738,103		)	(330,776		)	(2,477,099		)	(4,299		)	—			(2,812,174		)
Oil and natural gas properties, net	2,477			427,613			—		—			430,090			3,912			537,583			102,124			—			643,619
Other property and equipment, net	585			20,493			—		—			21,078
Investments in and advances to affiliates, net	502,864			—			—		(502,864		)	—
Derivative financial instruments - commodity derivatives	97			—			—		—			97
Other property and equipment, net and other non-current assets															909			20,090			17,565			—			38,564
Investments in and (advances to) affiliates, net															338,948			—			—			(338,948		)	—
Goodwill	13,293			149,862			—		—			163,155			13,293			149,862			—			—			163,155
Total assets	$	629,614		$	678,051		$	25,373	$	(502,864	)	$	830,174		$	419,006		$	810,842		$	153,670		$	(338,948	)	$	1,044,570
Liabilities and shareholders' equity
Liabilities and shareholders’ equity
Current maturities of long-term debt	$	1,333,989		$	—		$	—	$	—		$	1,333,989		$	473,364		$	—		$	—		$	—		$	473,364
Other current liabilities	14,163			187,327			—		—			201,490			22,534			70,016			6,341			—			98,891
Long-term debt	21,388			—			—		—			21,388
Derivative financial instruments - common share warrants	14,555			—			—		—			14,555
Other long-term liabilities	5,885			13,233			—		—			19,118			—			14,615			10,125			—			24,740
Liabilities subject to compromise															967,158			524,467			—			—			1,491,625
Payable to parent	—			2,416,991			—		(2,416,991		)	—			—			2,443,442			3,546			(2,446,988		)	—
Total shareholders' equity	(760,366		)	(1,939,500		)	25,373		1,914,127			(760,366		)
Total liabilities and shareholders' equity	$	629,614		$	678,051		$	25,373	$	(502,864	)	$	830,174
Total shareholders’ equity															(1,044,050		)	(2,241,698		)	133,658			2,108,040			(1,044,050		)
Total liabilities and shareholders’ equity															$	419,006		$	810,842		$	153,670		$	(338,948	)	$	1,044,570

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING BALANCE SHEET

As of December 31, ~~2016~~2017


(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	$	24,610		$	(15,542	)	$	—	$	—		$	9,068		$	49,170		$	(9,573	)	$	—	$	—		$	39,597
Restricted cash	—			11,150			—		—			11,150			—			15,271			—		—			15,271
Other current assets	6,463			83,936			—		—			90,399			22,697			90,265			—		—			112,962
Total current assets	31,073			79,544			—		—			110,617			71,867			95,963			—		—			167,830
Equity investments	—			—			24,365		—			24,365			—			—			14,181		—			14,181
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			97,080			—		—			97,080			—			118,652			—		—			118,652
Proved developed and undeveloped oil and natural gas properties	331,823			2,608,100			—		—			2,939,923			333,719			2,773,847			—		—			3,107,566
Accumulated depletion	(330,776		)	(2,371,469		)	—		—			(2,702,245		)	(330,777		)	(2,421,534		)	—		—			(2,752,311		)
Oil and natural gas properties, net	1,047			333,711			—		—			334,758			2,942			470,965			—		—			473,907
Other property and equipment, net	568			23,093			—		—			23,661
Investments in and advances to affiliates, net	430,168			—			—		(430,168		)	—
Deferred financing costs, net	4,376			—			—		—			4,376
Derivative financial instruments - commodity derivatives	482			—			—		—			482
Other property and equipment, net and other non-current assets															892			20,382			—		—			21,274
Investments in and (advances to) affiliates, net															466,055			—			—		(466,055		)	—
Goodwill	13,293			149,862			—		—			163,155			13,293			149,862			—		—			163,155
Total assets	$	481,007		$	586,210		$	24,365	$	(430,168	)	$	661,414		$	555,049		$	737,172		$	14,181	$	(466,055	)	$	840,347
Liabilities and shareholders' equity
Liabilities and shareholders’ equity
Current maturities of long-term debt	$	50,000		$	—		$	—	$	—		$	50,000		$	1,362,500		$	—		$	—	$	—		$	1,362,500
Other current liabilities	40,671			167,692			—		—			208,363			32,280			272,190			—		—			304,470
Long-term debt	1,258,538			—			—		—			1,258,538
Derivative financial instruments - common share warrants															1,950			—			—		—			1,950
Other long-term liabilities	3,704			12,715			—		—			16,419			4,518			13,108			—		—			17,626
Payable to parent	—			2,337,585			—		(2,337,585		)	—			—			2,447,586			—		(2,447,586		)	—
Total shareholders' equity	(871,906		)	(1,931,782		)	24,365		1,907,417			(871,906		)
Total liabilities and shareholders' equity	$	481,007		$	586,210		$	24,365	$	(430,168	)	$	661,414
Total shareholders’ equity															(846,199		)	(1,995,712		)	14,181		1,981,531			(846,199		)
Total liabilities and shareholders’ equity															$	555,049		$	737,172		$	14,181	$	(466,055	)	$	840,347

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the ~~three months ended~~ Three Months Ended September 30, ~~2017~~2018


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Oil and natural gas	$	—		$	61,229		$	—	$	—	$	61,229		$	—		$	87,761		$	5,779	$	—		$	93,540
Purchased natural gas and marketing	—			5,507			—		—		5,507			—			4,946			85		—			5,031
Total revenues	—			66,736			—		—		66,736			—			92,707			5,864		—			98,571
Costs and expenses:
Oil and natural gas production	—			12,259			—		—		12,259			—			16,585			731		—			17,316
Gathering and transportation	—			28,743			—		—		28,743			—			18,258			955		—			19,213
Purchased natural gas	—			5,388			—		—		5,388			—			3,776			—		—			3,776
Depletion, depreciation and amortization	88			13,430			—		—		13,518			75			18,533			2,005		—			20,613
Impairment of oil and natural gas properties	—			—			—		—		—
Accretion of discount on asset retirement obligations	—			221			—		—		221
Accretion of liabilities														—			234			318		—			552
General and administrative	(5,042		)	15,077			—		—		10,035			(9,647		)	14,448			1,314		—			6,115
Loss on Appalachia JV Settlement														—			—			240		—			240
Other operating items	—			1,714			—		—		1,714			—			(495		)	120		—			(375		)
Total costs and expenses	(4,954		)	76,832			—		—		71,878			(9,572		)	71,339			5,683		—			67,450
Operating income (loss)	4,954			(10,096		)	—		—		(5,142		)
Operating income														9,572			21,368			181		—			31,121
Other income (expense):
Interest expense, net	(32,888		)	—			—		—		(32,888		)	(8,993		)	—			—		—			(8,993		)
Gain on derivative financial instruments - commodity derivatives	860			—			—		—		860
Gain on derivative financial instruments - common share warrants	18,286			—			—		—		18,286
Loss on derivative financial instruments - common share warrants														(287		)	—			—		—			(287		)
Other income	13			12			—		—		25			4			8			—		—			12
Equity income	—			—			354		—		354
Net loss from consolidated subsidiaries	(9,730		)	—			—		9,730		—
Reorganization items, net														(18,169		)	—			—		—			(18,169		)
Net income from consolidated subsidiaries														21,557			—			—		(21,557		)	—
Total other income (expense)	(23,459		)	12			354		9,730		(13,363		)	(5,888		)	8			—		(21,557		)	(27,437		)
Income (loss) before income taxes	(18,505		)	(10,084		)	354		9,730		(18,505		)
Income before income taxes														3,684			21,376			181		(21,557		)	3,684
Income tax expense	319			—			—		—		319			—			—			—		—			—
Net income (loss)	$	(18,824	)	$	(10,084	)	$	354	$	9,730	$	(18,824	)
Net income														$	3,684		$	21,376		$	181	$	(21,557	)	$	3,684

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the ~~three months ended~~ Three Months Ended September 30, ~~2016~~2017


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	70,862		$	—		$	—	$	70,862		$	—		$	61,229		$	—	$	—	$	61,229
Purchased natural gas and marketing	—			6,324			—			—		6,324			—			5,507			—		—		5,507
Total revenues	—			77,186			—			—		77,186			—			66,736			—		—		66,736
Costs and expenses:
Oil and natural gas production	—			12,608			—			—		12,608			—			12,259			—		—		12,259
Gathering and transportation	—			27,979			—			—		27,979			—			28,743			—		—		28,743
Purchased natural gas	—			6,586			—			—		6,586			—			5,388			—		—		5,388
Depletion, depreciation and amortization	89			15,821			—			—		15,910			88			13,430			—		—		13,518
Impairment of oil and natural gas properties	—			—			—			—		—
Accretion of discount on asset retirement obligations	—			325			—			—		325
Accretion of liabilities															—			221			—		—		221
General and administrative	(4,395		)	15,141			—			—		10,746			(5,042		)	15,077			—		—		10,035
Other operating items	—			(1,110		)	—			—		(1,110		)	—			1,714			—		—		1,714
Total costs and expenses	(4,306		)	77,350			—			—		73,044			(4,954		)	76,832			—		—		71,878
Operating income (loss)	4,306			(164		)	—			—		4,142			4,954			(10,096		)	—		—		(5,142		)
Other income (expense):
Interest expense, net	(16,997		)	—			—			—		(16,997		)	(32,888		)	—			—		—		(32,888		)
Gain on derivative financial instruments - commodity derivatives	8,209			—			—			—		8,209			860			—			—		—		860
Gain on extinguishment of debt	57,421			—			—			—		57,421
Gain on derivative financial instruments - common share warrants															18,286			—			—		—		18,286
Other income	4			8			—			—		12			13			12			—		—		25
Equity loss	—			—			(823		)	—		(823		)
Equity income															—			—			354		—		354
Net loss from consolidated subsidiaries	(979		)	—			—			979		—			(9,730		)	—			—		9,730		—
Total other income (expense)	47,658			8			(823		)	979		47,822			(23,459		)	12			354		9,730		(13,363		)
Income (loss) before income taxes	51,964			(156		)	(823		)	979		51,964			(18,505		)	(10,084		)	354		9,730		(18,505		)
Income tax expense	1,028			—			—			—		1,028			319			—			—		—		319
Net income (loss)	$	50,936		$	(156	)	$	(823	)	$	979	$	50,936		$	(18,824	)	$	(10,084	)	$	354	$	9,730	$	(18,824	)

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the ~~nine months ended~~Nine Months Ended September 30, ~~2017~~2018


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	195,072		$	—	$	—	$	195,072		$	—		$	258,809		$	12,653		$	—	$	271,462
Purchased natural gas and marketing	—			19,208			—		—		19,208			—			15,477			226			—		15,703
Total revenues	—			214,280			—		—		214,280			—			274,286			12,879			—		287,165
Costs and expenses:
Oil and natural gas production	—			35,822			—		—		35,822			—			42,103			2,072			—		44,175
Gathering and transportation	—			83,183			—		—		83,183			—			58,164			2,335			—		60,499
Purchased natural gas	—			18,193			—		—		18,193			—			11,634			—			—		11,634
Depletion, depreciation and amortization	224			36,424			—		—		36,648			232			55,854			4,733			—		60,819
Impairment of oil and natural gas properties	—			—			—		—		—
Accretion of discount on asset retirement obligations	—			648			—		—		648
Accretion of liabilities														—			693			762			—		1,455
General and administrative	(32,169		)	45,225			—		—		13,056			(25,970		)	43,831			3,084			—		20,945
Gain on Appalachia JV Settlement														—			—			(119,237		)	—		(119,237		)
Other operating items	577			2,492			—		—		3,069			(35		)	(1,181		)	(166		)	—		(1,382		)
Total costs and expenses	(31,368		)	221,987			—		—		190,619			(25,773		)	211,098			(106,417		)	—		78,908
Operating income (loss)	31,368			(7,707		)	—		—		23,661
Operating income														25,773			63,188			119,296			—		208,257
Other income (expense):
Interest expense, net	(75,318		)	(2		)	—		—		(75,320		)	(25,981		)	—			—			—		(25,981		)
Gain on derivative financial instruments - commodity derivatives	22,934			—			—		—		22,934
Loss on derivative financial instruments - commodity derivatives														(615		)	—			—			—		(615		)
Gain on derivative financial instruments - common share warrants	146,585			—			—		—		146,585			1,428			—			—			—		1,428
Loss on restructuring of debt	(6,380		)	—			—		—		(6,380		)
Other income (loss)	14			(10		)	—		—		4
Other income														25			23			2			—		50
Equity income	—			—			1,009		—		1,009			—			—			179			—		179
Reorganization items, net														(78,260		)	(309,197		)	—			—		(387,457		)
Net loss from consolidated subsidiaries	(6,710		)	—			—		6,710		—			(126,509		)	—			—			126,509		—
Total other income (expense)	81,125			(12		)	1,009		6,710		88,832			(229,912		)	(309,174		)	181			126,509		(412,396		)
Income (loss) before income taxes	112,493			(7,719		)	1,009		6,710		112,493			(204,139		)	(245,986		)	119,477			126,509		(204,139		)
Income tax expense	2,374			—			—		—		2,374
Income tax benefit														(4,518		)	—			—			—		(4,518		)
Net income (loss)	$	110,119		$	(7,719	)	$	1,009	$	6,710	$	110,119		$	(199,621	)	$	(245,986	)	$	119,477		$	126,509	$	(199,621	)

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the ~~nine months ended~~Nine Months Ended September 30, ~~2016~~2017


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	176,732		$	—		$	—	$	176,732		$	—		$	195,072		$	—	$	—	$	195,072
Purchased natural gas and marketing	—			15,335			—			—		15,335			—			19,208			—		—		19,208
Total revenues	—			192,067			—			—		192,067			—			214,280			—		—		214,280
Costs and expenses:
Oil and natural gas production	4			39,139			—			—		39,143			—			35,822			—		—		35,822
Gathering and transportation	—			79,828			—			—		79,828			—			83,183			—		—		83,183
Purchased natural gas	—			17,273			—			—		17,273			—			18,193			—		—		18,193
Depletion, depreciation and amortization	298			63,697			—			—		63,995			224			36,424			—		—		36,648
Impairment of oil and natural gas properties	838			159,975			—			—		160,813
Accretion of discount on asset retirement obligations	—			2,006			—			—		2,006
Accretion of liabilities															—			648			—		—		648
General and administrative	(6,062		)	44,688			—			—		38,626			(32,169		)	45,225			—		—		13,056
Other operating items	(406		)	24,342			—			—		23,936			577			2,492			—		—		3,069
Total costs and expenses	(5,328		)	430,948			—			—		425,620			(31,368		)	221,987			—		—		190,619
Operating income (loss)	5,328			(238,881		)	—			—		(233,553		)
Operating income															31,368			(7,707		)	—		—		23,661
Other income (expense):
Interest expense, net	(54,186		)	—			—			—		(54,186		)	(75,318		)	(2		)	—		—		(75,320		)
Loss on derivative financial instruments - commodity derivatives	(11,632		)	—			—			—		(11,632		)
Gain on extinguishment of debt	119,374			—			—			—		119,374
Other income	9			28			—			—		37
Equity loss	—			—			(8,824		)	—		(8,824		)
Gain on derivative financial instruments - commodity derivatives															22,934			—			—		—		22,934
Gain on derivative financial instruments - common share warrants															146,585			—			—		—		146,585
Loss on restructuring of debt															(6,380		)	—			—		—		(6,380		)
Other income (expense)															14			(10		)	—		—		4
Equity income															—			—			1,009		—		1,009
Net loss from consolidated subsidiaries	(247,677		)	—			—			247,677		—			(6,710		)	—			—		6,710		—
Total other income (expense)	(194,112		)	28			(8,824		)	247,677		44,769			81,125			(12		)	1,009		6,710		88,832
Loss before income taxes	(188,784		)	(238,853		)	(8,824		)	247,677		(188,784		)
Income (loss) before income taxes															112,493			(7,719		)	1,009		6,710		112,493
Income tax expense	1,775			—			—			—		1,775			2,374			—			—		—		2,374
Net loss	$	(190,559	)	$	(238,853	)	$	(8,824	)	$	247,677	$	(190,559	)
Net income (loss)															$	110,119		$	(7,719	)	$	1,009	$	6,710	$	110,119

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the ~~nine months ended~~ Nine Months Ended September 30, ~~2017~~2018


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(9,637	)	$	60,744		$	—	$	—	$	51,107		$	(18,946	)	$	122,746		$	5,736	$	—	$	109,536
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,011		)	(114,663		)	—		—		(115,674		)	(921		)	(128,835		)	14,450		—		(115,306		)
Proceeds from disposition of property and equipment	—			25			—		—		25
Restricted cash	—			(12,229		)	—		—		(12,229		)
Net changes in amounts due to joint ventures	—			(9,498		)	—		—		(9,498		)
Other														—			950			—		—		950
Advances/investments with affiliates	(79,406		)	79,406			—		—		—			598			(4,144		)	3,546		—		—
Net cash used in investing activities	(80,417		)	(56,959		)	—		—		(137,376		)
Net cash provided by (used in) investing activities														(323		)	(132,029		)	17,996		—		(114,356		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	163,401			—			—		—		163,401
Borrowings under DIP Credit Agreement														156,406			—			—		—		156,406
Repayments under EXCO Resources Credit Agreement	(265,592		)	—			—		—		(265,592		)	(126,401		)	—			—		—		(126,401		)
Proceeds received from issuance of 1.5 Lien Notes, net	295,530			—			—		—		295,530
Payments on Exchange Term Loan	(11,602		)	—			—		—		(11,602		)
Debt financing costs and other	(22,077		)	—			—		—		(22,077		)	(6,062		)	—			—		—		(6,062		)
Net cash provided by financing activities	159,660			—			—		—		159,660			23,943			—			—		—		23,943
Net increase in cash	69,606			3,785			—		—		73,391
Cash at beginning of period	24,610			(15,542		)	—		—		9,068
Cash at end of period	$	94,216		$	(11,757	)	$	—	$	—	$	82,459
Net increase (decrease) in cash, cash equivalents and restricted cash														4,674			(9,283		)	23,732		—		19,123
Cash, cash equivalents and restricted cash at beginning of period														49,170			5,698			—		—		54,868
Cash, cash equivalents and restricted cash at end of period														$	53,844		$	(3,585	)	$	23,732	$	—	$	73,991

EXCO RESOURCES, INC. (DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the ~~nine months ended~~ Nine Months Ended September 30, ~~2016~~2017


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated			Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	9,152		$	(12,892	)	$	—	$	—	$	(3,740	)	$	(9,637	)	$	60,744		$	—	$	—	$	51,107
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,250		)	(69,205		)	—		—		(70,455		)	(1,011		)	(114,663		)	—		—		(115,674		)
Proceeds from disposition of property and equipment	10			11,232			—		—		11,242			—			25			—		—		25
Restricted cash	—			686			—		—		686
Net changes in amounts due to joint ventures	—			2,377			—		—		2,377			—			(9,498		)	—		—		(9,498		)
Advances/investments with affiliates	(83,631		)	83,631			—		—		—			(79,406		)	79,406			—		—		—
Net cash provided by (used in) investing activities	(84,871		)	28,721			—		—		(56,150		)
Net cash used in investing activities														(80,417		)	(44,730		)	—		—		(125,147		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	390,897			—			—		—		390,897			163,401			—			—		—		163,401
Repayments under EXCO Resources Credit Agreement	(243,797		)	—			—		—		(243,797		)	(265,592		)	—			—		—		(265,592		)
Payments on Exchange Term Loan	(38,056		)	—			—		—		(38,056		)
Repurchases of senior unsecured notes	(53,298		)	—			—		—		(53,298		)
Proceeds received from issuance of 1.5 Lien Notes, net														295,530			—			—		—		295,530
Payments on Second Lien Term Loans														(11,602		)	—			—		—		(11,602		)
Debt financing costs and other	(4,569		)	—			—		—		(4,569		)	(22,077		)	—			—		—		(22,077		)
Net cash provided by financing activities	51,177			—			—		—		51,177			159,660			—			—		—		159,660
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
Net increase (decrease) in cash, cash equivalents and restricted cash														69,606			16,014			—		—		85,620
Cash, cash equivalents and restricted cash at beginning of period														24,610			(4,392		)	—		—		20,218
Cash, cash equivalents and restricted cash at end of period														$	94,216		$	11,622		$	—	$	—	$	105,838

12.Subsequent events

As of September 30, 2018, we had withheld $28.5 million in revenues owed to Shell as a result of a dispute regarding the failure of Shell Energy North America (US) LP ("Shell Energy"), a subsidiary of Shell, to pay us for the sale of natural gas. We entered into a settlement agreement with Shell on September 17, 2018 that was approved by the Court on October 1, 2018. Under the terms of the settlement agreement:

EXCO will pay a total of $22.5 million to Shell, including $9.0 million within 15 days following the approval of the settlement agreement by the Court, $9.0 million within 45 days following the approval of the Court, and the remaining $4.5 million on or before the effective date of the plan of reorganization. Upon payment in full of these amounts, Shell shall release EXCO from any further liability related to the withheld revenues;

EXCO will commence the completion of four wells that were previously drilled in North Louisiana no later than November 15, 2018, and subsequently commence the completion of three additional wells that were previously drilled in North Louisiana;

EXCO shall assume the joint development agreement with Shell for the East Texas/ North Louisiana joint venture as part of the bankruptcy proceedings and any defaults occurring thereunder are deemed to be satisfied; and

Shell shall not challenge EXCO’s right to serve as operator under the joint development agreement for the East Texas/ North Louisiana joint venture for the remaining term through January 1, 2020, subject to certain exceptions.

The settlement agreement does not prevent us from asserting any claim, cross-claim, defense, or other cause of action against Shell Energy, nor does the settlement agreement prevent Shell Energy from asserting any claim, cross-claim, defense, or other cause of action against us. Furthermore, the settlement agreement provides that it shall not affect any proof of claim that Shell Energy filed in the Chapter 11 Cases. As of September 30, 2018, we had a receivable of approximately $33.4 million related to the sales of natural gas to Shell Energy in East Texas and North Louisiana for the months of November and December 2017. Shell Energy is withholding payment as a means to satisfy their demands of reasonable assurance of performance under a natural gas sales agreement. We believe the request for adequate assurance was unreasonable and unjustified under the terms of the agreement and these amounts have been improperly withheld by Shell Energy. On March 7, 2018, the Court approved the rejection of the aforementioned natural gas sales agreement with Shell Energy and we recorded a liability of $41.5 million in “Liabilities subject to compromise” related to our current estimate of the allowed claim. See further discussion regarding this dispute with Shell Energy in the 2017 Form 10-K and other periodic filings with the SEC.

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

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

Forward-looking statements

This Quarterly Report on Form 10-Q contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended ("(“Securities ~~Act"~~Act”) and Section 21E of the Securities Exchange Act of 1934, as amended ("(“the Exchange ~~Act"~~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 commodity derivative financial instruments;

our liquidity and capital resources; 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 our 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 and the documents incorporated herein by reference, including, but not limited to:

bankruptcy proceedings and the effect of those proceedings on our ongoing and future operations, including the actions of the Court and our creditors;

our ability to ~~continue~~enter into transactions as a ~~going concern;~~

~~the outcome~~result of our ~~review of strategic alternatives, which may include, but not be limited to, seeking a comprehensive out-of-court restructuring or reorganization under~~ Chapter 11 ~~of the U.S. Bankruptcy Code;~~filing, including commodity derivative contracts with financial institutions and services with vendors;

our future cash ~~flow~~flows and ~~Liquidity;~~the adequacy to fund the significant costs associated with the bankruptcy process, including our ability to limit these costs by obtaining confirmation of a successful plan of reorganization in a timely manner;

our ability to obtain the requisite number of votes required to obtain confirmation of the contemplated plan of reorganization or an alternative restructuring transaction;

our ability to maintain compliance with debt covenants and ~~decisions~~ to ~~pay interest on~~meet debt service obligations associated with the ~~1.5 Lien Notes and 1.75 Lien Term Loans~~DIP Credit Agreement;

our ability to obtain exit financing in ~~cash, common shares~~order to consummate the contemplated plan of reorganization or ~~additional indebtedness;~~an alternative restructuring transaction;

future capital requirements and availability of financing, including limitations on our ability to incur certain types of indebtedness under our debt agreements and to refinance or replace existing debt ~~obligations as they mature;~~

~~our ability to meet our current and future debt service obligations, including our upcoming 2018 debt maturities;~~

~~our ability to maintain compliance with our debt covenants;~~obligations;

fluctuations in the prices of oil and natural gas;

the availability of oil and natural gas;

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;

~~outcome of divestitures of non-core assets;~~

~~our ability to enter into transactions as a result of our credit rating, including commodity derivatives with financial institutions and services with vendors;~~

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

availability of drilling and production equipment;

availability of water, sand 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 regain compliance 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 commodity derivative financial instruments;~~production;

our ability and decisions whether or not to enter into commodity derivative financial instruments;

potential acts of terrorism;

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

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

fluctuations in interest rates;

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

our ability to execute our business strategies and other corporate ~~actions.~~actions; 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 risk factors and other 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, ~~2016,~~2017, filed with the Securities and Exchange Commission ~~("SEC"~~(“SEC”) on March ~~16,~~ 15, 2018 (“2017 ~~("2016~~ Form ~~10-K"~~10-K”).

Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas and the availability of capital from our debtor-in-possession credit agreement ~~("EXCO Resources~~(“DIP Credit ~~Agreement"~~Agreement”) and other sources. 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

Recent developments

Chapter 11 Cases

On January 15, 2018 (“Petition Date”), the ~~exploitation~~Company and ~~development~~certain of ~~our shale resource plays~~its subsidiaries, including EXCO Services, Inc., EXCO Partners GP, LLC, EXCO GP Partners OLP, LP, EXCO Partners OLP GP, LLC, EXCO Operating Company, LP, EXCO Midcontinent MLP, LLC, EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC, EXCO Resources (XA), LLC, EXCO Production Company (WV), LLC, EXCO Land Company, LLC, EXCO Holding MLP, Inc., Raider Marketing, LP and Raider Marketing GP, LLC (collectively, the ~~pursuit~~“Filing Subsidiaries” and, together with the Company, the “Debtors”), filed voluntary petitions for relief under Chapter 11 of ~~leasing and acquisition opportunities.~~

~~Like~~the Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (“Court”). The cases are being jointly administered under the caption In Re EXCO Resources, Inc., Case No. 18-30155 (MI) (“Chapter 11 Cases”). The Court has granted all ~~oil and natural gas exploration and production companies, we face~~of the ~~challenge of natural production declines. We attempt~~first day motions filed by the Debtors that were designed primarily to ~~offset~~minimize the impact of ~~this natural decline by implementing drilling~~the Chapter 11 Cases on our operations, customers and ~~exploitation projects~~employees. The Debtors continue to ~~identify~~operate their businesses as “debtors in possession” under the jurisdiction of the Court and ~~develop additional reserves~~in accordance with the applicable provisions of the Bankruptcy Code and ~~by adding reserves through leasing~~orders of the Court. The Debtors expect to continue operations without interruption during the pendency of the Chapter 11 Cases.

On January 22, 2018, we closed the DIP Credit Agreement with lenders including affiliates of Fairfax Financial Holdings Limited (“Fairfax”), Bluescape Resources Company LLC (“Bluescape”) and ~~undeveloped acreage acquisition opportunities. Our liquidity,~~JPMorgan Chase Bank, N.A. (collectively the “DIP Lenders”), which ~~we define as cash and restricted cash plus~~includes an initial borrowing base of $250.0 million. Proceeds from the ~~unused borrowing base~~DIP Facilities were used to repay all obligations outstanding under the EXCO Resources Credit Agreement ~~("Liquidity")~~and will provide additional liquidity to fund our operations during the Chapter 11 Cases.

For the duration of the Chapter 11 Cases, our operations and ability to ~~maintain compliance~~develop and execute our business plan are subject to risks and uncertainties associated with ~~debt covenants have been negatively impacted by~~ the ~~prolonged depressed oil~~Chapter 11 Cases. As a result of these risks and ~~natural gas price environment, levels~~uncertainties, our assets, liabilities, shareholders’ equity, officers and/or directors could be significantly different following the outcome of ~~indebtedness,~~the Chapter 11 Cases, and ~~gathering, transportation~~the description of our operations, properties and ~~certain other commercial contracts.~~capital plans included in this quarterly report on Form 10-Q may not accurately reflect our operations, properties and capital plans following the conclusion of the Chapter 11 Cases. See ~~"Note~~further discussion of the impact of the bankruptcy proceedings as part of “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~~

~~Restructuring activities~~

On September 7, 2017, we announced that our Board of Directors has delegated authority to the independent directors of the Audit Committee of the Board of Directors ("Audit Committee") to explore strategic alternatives to strengthen the Company’s balance sheet and maximize the value of the Company, which may include, but not limited to, seeking reorganization under Chapter 11 of the U.S. Bankruptcy Code. We, at the direction of the Audit Committee, have retained PJT Partners LP as financial advisors and Alvarez & Marsal North America, LLC as restructuring advisors, and have engaged in discussions with certain stakeholders regarding strategic alternatives to restructure our balance sheet. We continue to retain Kirkland & Ellis LLP as our legal advisor to assist the Audit Committee and management team with the strategic review process.

~~EXCO Resources Credit Agreement amendment~~

During the third quarter of 2017, we borrowed substantially all of our remaining unused commitments and had $126.4 million of outstanding indebtedness and $23.6 million of outstanding letters of credit under the EXCO Resources Credit Agreement as of September 30, 2017. As a result, we had no availability remaining under the EXCO Resources Credit Agreement, including letters of credit, as of September 30, 2017. 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. The redetermination of the borrowing base scheduled for November 2017 is currently in process. 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 the redetermination.

On September 29, 2017, we obtained a limited one-time waiver from the lenders under the EXCO Resources Credit agreement waiving an event of default as a result of a failure to comply with the Aggregate Revolving Credit Exposure ratio as of September 30, 2017. See further discussion in "Note 1. Organization and basis of presentation"presentation” in the Notes to our Condensed Consolidated Financial Statements.

~~Changes to Board of Directors~~

On September 20, 2017, each of B. James Ford and Samuel A. Mitchell resigned from their respective positions as members of our Board of Directors ("Board"). At the time of their respective resignations, neither Mr. Ford nor Mr. Mitchell was a member of any committee of the Board. On October 6, 2017, Stephen J. Toy resigned from his position as a member of the Board. At the time of his resignation, Mr. Toy was a member of each of the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee of the Board. Following these resignations, we will continue to have the required number of independent directorsImpact on our ~~Board committees, as well as a majority of independent directors, in each case for purposes of NYSE listing rules.~~

~~NYSE compliance~~

On June 2, 2017, we filed a certificate of amendment to our Amended and Restated Certificate of Formation to reduce the number of authorized common shares from 780,000,000 to 260,000,000 and effect a 1-for-15 reverse share split. The reverse share split became effective after the market closed on June 12, 2017. See "Note 1. Organization and basis of presentation" in the Notes to our Condensed Consolidated Financial Statements for further discussion.

To maintain compliance with the NYSE's continued listing standards, the Company's common shares are required, among other things, to maintain an average closing price of $1.00 or more over a consecutive 30 trading-day period. As a result of the reverse share split, the per share market price of our common shares increased above $1.00, the minimum average closing price required to maintain the listing of our common shares on the NYSE. On July 11, 2017, we were notified by the NYSE that we had regained compliance with Section 802.01C of the NYSE's continued listing standards because the price of our common shares on June 30, 2017, and the average price of our common shares over the thirty trading days prior to June 30, 2017, exceeded $1.00 per share.

In addition, the Company's average global market capitalization cannot average less than $50 million over a consecutive 30 trading-day period at the same time that its shareholders' equity is less than $50 million. On August 10, 2017, we were notified by the NYSE that EXCO's market capitalization had averaged less than $50 million for more than 30 consecutive trading days while its shareholders' equity was less than $50 million. On September 22, 2017, we submitted to the NYSE our business plan setting forth how we intend to regain compliance with the NYSE's market capitalization requirements, and, on November 2, 2017, the NYSE accepted our business plan. If we fail to comply, or regain compliance with, the continued listing standards of the NYSE by February 10, 2019, it will result in a delisting of our common shares from the NYSE. In addition, if our market capitalization falls to $15 million for a 30 trading-day period or our share price falls to an abnormally low level, the NYSE may immediately suspend trading and commence delisting of our common shares.

~~Termination of South Texas Divestiture~~

On April 7, 2017, we entered into a purchase and sale agreement with a subsidiary of Venado Oil and Gas, LLC ("Venado") to divest our oil and natural gas properties and surface acreage in South Texas for a total purchase price of $300.0 million that was subject to closing conditions and adjustments based on an effective date of January 1, 2017.

Scheduled Closing Date. The purchase agreement included conditions to the closing, including seller's representation and warranty regarding all material contracts being in full force and effect be true as of the Original Scheduled Closing Date. As described in "Note 3. Acquisitions, divestitures and other significant events", the closing conditions were not anticipated to be satisfied or waived by the Original Scheduled Closing Date due to the purported termination of a long-term natural gas sales contract by Chesapeake Energy Marketing, L.L.C. (“CEML”). Therefore, we entered into an amendment to extend the Original Scheduled Closing Date to August 15, 2017.indebtedness

The ~~amendment, among other things, provided that the satisfaction~~commencement of the ~~closing conditions would be deemed satisfied by the reinstatement~~Chapter 11 Cases constituted an event of ~~the natural gas sales contract or by entry into a new gathering agreement. Because all closing conditions had not been satisfied or waived by August 15, 2017,~~ default that accelerated our obligations under our previous revolving credit agreement (“EXCO ~~and Venado mutually agreed to terminate the purchase and sale agreement, effective as of August 15, 2017. Following the termination, the purchase and sale agreement was void and of no further effect.~~

~~Financing Transactions~~

~~On March 15, 2017, we closed a series of transactions including the issuance of $300.0 million in aggregate principal amount of~~Resources Credit Agreement”), senior secured 1.5 lien notes due March 20, 2022 ("(“1.5 Lien ~~Notes"~~Notes”), ~~exchange of $682.8 million in aggregate principal amount of our~~ senior secured ~~second lien term loans due October 26, 2020 ("Second Lien Term Loans") for a like amount of senior~~ 1.75 lien term loans due October 26, 2020 ("(“1.75 Lien Term ~~Loans"~~Loans”), senior unsecured notes due September 15, 2018 (“2018 Notes”), and ~~such exchange the "Second Lien Term Loan Exchange") and issuance of warrants to purchase our common shares ("2017 Warrants"~~senior unsecured notes due April 15, 2022 (“2022 Notes”). ~~The terms~~These debt instruments provide that as a result of the ~~indenture governing~~commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code.

As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in the Chapter 11 Cases. These amounts represent our current estimate and may materially differ from actual future settlement amounts paid. As of September 30, 2018, the carrying value for each of our debt instruments approximates the principal amount. The corresponding expense associated with the adjustments was recorded as “Reorganization items, net” on our Condensed Consolidated Statement of Operations for the nine months ended September 30, 2018.

On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien ~~Notes and the credit agreement governing the~~Notes. We accrued interest on 1.75 Lien Term Loans, ~~allow for~~senior secured second lien term loans

due October 26, 2020 (“Second Lien Term Loans”), 2018 Notes and 2022 Notes through the Petition Date, with no interest ~~payments~~accrued subsequent to the filings. As a result, we expect our interest expense to decrease in ~~cash common shares~~the future.

Rejection of executory contracts

Subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or ~~additional indebtedness (such interest payments in common shares~~reject certain executory contracts and unexpired leases subject to the approval of the Court and fulfillment of certain other conditions. The rejection of an executory contract or ~~additional indebtedness, "PIK Payments") ,~~unexpired lease is generally treated as a breach as of the Petition Date of such executory contract or unexpired lease and, subject to certain ~~restrictions and limitations. The transaction fees paid~~exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but may give rise to a general unsecured claim against the Company or the applicable Filing Subsidiaries for damages caused by such rejection. Our estimate of allowable claims related to the ~~lenders included a combination~~executory contracts and unexpired leases approved for rejection by the Court was recorded as “Liabilities subject to compromise” on our Condensed Consolidated Balance Sheet as of ~~cash~~September 30, 2018 and ~~warrants to purchase~~the corresponding expense was recorded as “Reorganization items, net” in our ~~common shares. The 1.5 Lien Notes were issued to affiliates~~Condensed Consolidated Statement of ~~Fairfax Financial Holdings Limited ("Fairfax"), Bluescape Resources Company LLC ("Bluescape")~~Operations for the three and ~~Oaktree Capital Management, LP ("Oaktree"), as well as an unaffiliated lender.~~nine months ended September 30, 2018.

During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. We expect our realized natural gas price differentials and transportation expenses to improve in the future as a result of the rejection of these contracts.

On March 1, 2018, the Debtors filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018. The ~~proceeds~~motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP and Raider Marketing, LP commenced an adversary proceeding (Adv. Proc. No. 18-03096) against Azure to establish that the minimum volume commitment agreement is severable from the ~~1.5 Lien Notes~~base gathering agreement between the parties. The Debtors and the contract counterparties each filed various dispositive motions that were ~~primarily utilized~~heard by the Court on August 9, 2018. The parties have engaged in settlement discussions related to ~~repay~~this matter; however, there can be no assurance the ~~outstanding indebtedness under~~parties will be able to reach an agreement. Any settlement reached between the ~~EXCO Resources Credit Agreement as of March 2017. In connection with these transactions,~~parties would have to be approved by the ~~EXCO Resources Credit Agreement was amended to reduce~~Court.

On August 9, 2018, the ~~borrowing base to $150.0 million, permit~~Court approved the ~~issuance~~rejection of the ~~1.5 Lien Notes~~office lease for our corporate headquarters in Dallas, Texas. We subsequently entered into a new lease for a reduced amount of square footage in the same office building with a term through December 31, 2022. We expect our rent expense included within general and administrative expenses to decrease in the ~~exchange~~future as a result of ~~Second Lien Term Loans,~~the rejection of this contract.

Plan of Reorganization

On October 1, 2018, the Debtors filed a Settlement Joint Chapter 11 Plan of Reorganization (the “Plan”) and ~~modify certain financial covenants.~~related Disclosure Statement with the Court. On November 5, 2018, the Court authorized us to solicit acceptances of the Plan and approved the Disclosure Statement and other related solicitation materials and procedures necessary to approve the Plan. We are currently in the process of soliciting votes with respect to the Plan. A hearing to consider confirmation of the Plan is scheduled to be held on December 10, 2018 in the Court (the “Confirmation Hearing”). If the Plan is ultimately confirmed by the Court, the Debtors would emerge from bankruptcy pursuant to the terms of the Plan. See further discussion of ~~these transactions as part~~the key proposed restructuring elements contemplated in the Plan and the confirmation process in “Note 1. Organization and basis of ~~"Note 8. Debt"~~presentation” in the Notes to our Condensed Consolidated Financial Statements.

Appalachia JV Settlement

On February 27, 2018, we closed a settlement agreement with a subsidiary of Shell to resolve arbitration regarding our right to participate in an area of mutual interest in the Appalachia region (“Appalachia JV Settlement”). As a result of the Appalachia JV Settlement, we acquired Shell’s interests in our joint venture in Appalachia, including entities that own interests in oil and natural gas properties, an entity that operates the wells in the joint venture in Appalachia (“OPCO”) and an entity that owns and operates midstream assets in the Appalachia region (“Appalachia Midstream”). As a result, our production, revenues and expenses in the Appalachia region are expected to increase in the future. Also, our recoveries of general and administrative expenses related to the joint venture in Appalachia are expected to decrease in the future. See further discussion of this settlement as part of “Note 3. Acquisitions, divestitures and other significant events” in the Notes to our Condensed Consolidated Financial Statements.

Critical accounting policies

We consider accounting policies related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, equity-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the ~~time~~date of the ~~estimates were made. However,~~condensed consolidated financial statements. Actual results could differ from these ~~estimates could change materially if different information or assumptions were used.~~estimates. These policies and others are summarized in ~~Management’s Discussion~~the 2017 Form 10-K. In addition, see further discussion of our application of ASC 852 (as defined below) as a result of the Chapter 11 Cases in “Note 1. Organization and ~~Analysis~~basis of presentation” in the Notes to our Condensed Consolidated Financial ~~Condition and Results of Operations in EXCO's 2016 Form 10-K.~~Statements.

Accounting during bankruptcy

Our results of operations

A summary of key financial data for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~2017 related to our results of operations is presented below:


	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)	2017			2016					2017			2016				Period to period change			2018			2017				Quarter to quarter change			2018				2017			Period to period change
Production:						Quarter to quarter change
Oil (Mbbls)	276			391		(115		)		910			1,388			(478		)		377			276			101				989				910		79
Natural gas (Mmcf)	20,178			24,107		(3,929		)		58,964			71,926			(12,962		)		24,780			20,178			4,602				76,090				58,964		17,126
Total production (Mmcfe) (1)	21,834			26,453		(4,619		)		64,424			80,254			(15,830		)		27,042			21,834			5,208				82,024				64,424		17,600
Average daily production (Mmcfe)	237			288		(51		)		236			293			(57		)		294			237			57				300				236		64
Revenues before commodity derivative financial instrument activities:
Oil	$	12,906		$	16,215	$	(3,309	)		$	43,403		$	49,688		$	(6,285	)		$	27,243		$	12,906		$	14,337			$	67,854			$	43,403	$	24,451
Natural gas	48,323			54,647		(6,324		)		151,669			127,044			24,625				66,297			48,323			17,974				203,608				151,669		51,939
Total oil and natural gas revenues	61,229			70,862		(9,633		)		195,072			176,732			18,340				93,540			61,229			32,311				271,462				195,072		76,390
Purchased natural gas and marketing	5,507			6,324		(817		)		19,208			15,335			3,873				5,031			5,507			(476		)		15,703				19,208		(3,505		)
Total revenues	$	66,736		$	77,186	$	(10,450	)		$	214,280		$	192,067		$	22,213			$	98,571		$	66,736		$	31,835			$	287,165			$	214,280	$	72,885
Commodity derivative financial instruments:
Gain (loss) on derivative financial instruments - commodity derivatives	$	860		$	8,209	$	(7,349	)		$	22,934		$	(11,632	)	$	34,566			$	—		$	860		$	(860	)		$	(615	)		$	22,934	$	(23,549	)
Average sales price (before cash settlements of commodity derivative financial instruments):
Oil (per Bbl)	$	46.76		$	41.47	$	5.29			$	47.70		$	35.80		$	11.90			$	72.26		$	46.76		$	25.50			$	68.61			$	47.70	$	20.91
Natural gas (per Mcf)	2.39			2.27		0.12				2.57			1.77			0.80				2.68			2.39			0.29				2.68				2.57		0.11
Natural gas equivalent (per Mcfe)	2.80			2.68		0.12				3.03			2.20			0.83				3.46			2.80			0.66				3.31				3.03		0.28
Costs and expenses:
Oil and natural gas operating costs	$	9,215		$	8,797	$	418			$	25,928		$	25,835		$	93			$	13,010		$	9,215		$	3,795			$	31,792			$	25,928	$	5,864
Production and ad valorem taxes	3,044			3,811		(767		)		9,894			13,308			(3,414		)		4,306			3,044			1,262				12,383				9,894		2,489
Gathering and transportation	28,743			27,979		764				83,183			79,828			3,355				19,213			28,743			(9,530		)		60,499				83,183		(22,684		)
Purchased natural gas	5,388			6,586		(1,198		)		18,193			17,273			920				3,776			5,388			(1,612		)		11,634				18,193		(6,559		)
Depletion	13,297			15,528		(2,231		)		35,858			62,848			(26,990		)		20,255			13,297			6,958				59,862				35,858		24,004
Depreciation and amortization	221			382		(161		)		790			1,147			(357		)		358			221			137				957				790		167
General and administrative (2)	10,035			10,746		(711		)		13,056			38,626			(25,570		)		6,115			10,035			(3,920		)		20,945				13,056		7,889
Interest expense, net	32,888			16,997		15,891				75,320			54,186			21,134				8,993			32,888			(23,895		)		25,981				75,320		(49,339		)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.42		$	0.33	$	0.09			$	0.40		$	0.32		$	0.08			$	0.48		$	0.42		$	0.06			$	0.39			$	0.40	$	(0.01	)
Production and ad valorem taxes	0.14			0.14		—				0.15			0.17			(0.02		)		0.16			0.14			0.02				0.15				0.15		—
Gathering and transportation	1.32			1.06		0.26				1.29			0.99			0.30				0.71			1.32			(0.61		)		0.74				1.29		(0.55		)
Depletion	0.61			0.59		0.02				0.56			0.78			(0.22		)		0.75			0.61			0.14				0.73				0.56		0.17
Depreciation and amortization	0.01			0.01		—				0.01			0.01			—				0.01			0.01			—				0.01				0.01		—
Net income (loss) ~~(3)~~	$	(18,824	)	$	50,936	$	(69,760	)		$	110,119		$	(190,559	)	$	300,678			$	3,684		$	(18,824	)	$	22,508			$	(199,621	)		$	110,119	$	(309,740	)


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

(2)

Equity-based compensation included in general and administrative expense was expense of $0.5 million and income of $0.9 ~~million and expense of $1.4~~ million for the three months ended September 30, 2018 and 2017, respectively, and ~~2016, respectively,~~expense of $1.5 million and income of $11.2 ~~million and expense of $14.6~~ million for the nine months ended September 30, ~~2017~~2018 and ~~2016,~~2017, respectively.

~~(3)~~

Net income for the three and nine months ended September 30, 2017 included $18.3 million and $146.6 million of gains related to the revaluation of the 2017 Warrants, respectively. See "Note 7. Derivative financial instruments" in the Notes to our Condensed Consolidated Financial Statements for further discussion. Net loss for the nine months ended September 30, 2016 included $160.8 million of impairments of oil and natural gas properties. See "Note 5. Oil and natural gas properties" in the Notes to our Condensed Consolidated Financial Statements for further discussion. Net losses for the three and nine months ended September 30, 2016 were partially offset by net gains 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, ~~2017~~2018 and ~~2016~~.2017. The comparability of our results of operations for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~2017 was affected by:

changes in general and administrative expenses as a result of legal and professional fees incurred in connection with the restructuring process;

rejection of certain executory contracts as part of the Chapter 11 Cases related to the sale, marketing and transportation of natural gas in the North Louisiana region, and the office lease for our corporate headquarters;

impact of the Chapter 11 Cases on our indebtedness, including the adjustments to the carrying value as well as the accrual of interest during the pendency of the bankruptcy proceedings;

gains from the settlement of litigation with our Appalachian joint venture partner during 2018;

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;~~

~~asset impairments and other non-recurring costs;~~

mark-to-market gains and losses from our derivative financial instruments, including ~~significant~~ gains on the 2017 Warrants due to a decrease in ~~EXCO's~~EXCO’s share price;

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

~~the sale of our shallow conventional assets in Appalachia~~ and ~~the settlement of the litigation with our Eagle Ford shale joint venture partner during 2016;~~

the impact of ~~declining~~development activities on our oil and natural gas ~~production volumes from our reduced drilling activities;~~production.

significant changes in our capital structure as a result of transactions in 2017 and 2016, including the issuance of the 1.5 Lien Notes and 1.75 Lien Term Loans on March 15, 2017 and repurchases of our 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and our 8.5% senior unsecured notes due April 15, 2022 ("2022 Notes") during 2016;

~~changes in general and administrative expenses as a result of legal and advisory fees incurred in connection with the restructuring of our balance sheet; and~~

~~the reductions in our workforce that occurred during 2016.~~

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

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

the level of domestic and international production;

the availability of imported oil and natural gas;

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

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

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

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

the cost and availability of other competitive fuels;

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

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

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

the availability of refining capacity;

technological advances affecting oil and natural gas production and consumption;

weather conditions and natural disasters;

foreign and domestic government relations; and

overall domestic and global economic conditions.

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

Oil and natural gas production, revenues and prices

The following table presents our production, revenue and average sales prices for the three and nine months ended September 30, ~~2017~~2018 and ~~2016:~~

Three Months Ended September 30,
2017 2016 Quarter to quarter change
(dollars in thousands, except per unit rate) Production (Mmcfe) Revenue $/Mcfe Production (Mmcfe) Revenue $/Mcfe Production (Mmcfe) Revenue $/Mcfe
Producing region:
North Louisiana 13,768
$ 35,544
$ 2.58
14,633
$ 34,856
$ 2.38
(865 ) $ 688
$ 0.20
East Texas 3,736
9,716
2.60
6,312
16,424
2.60
(2,576 ) (6,708 ) —
South Texas 1,865
11,574
6.21
2,517
14,953
5.94
(652 ) (3,379 ) 0.27
Appalachia and other 2,465
4,395
1.78
2,991
4,629
1.55
(526 ) (234 ) 0.23
Total 21,834
$ 61,229
$ 2.80
26,453
$ 70,862
$ 2.68
(4,619 ) $ (9,633 ) $ 0.12
2017:


	Nine Months Ended September 30,																	Three Months Ended September 30,
	2017					2016					Period to period change							2018					2017					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	37,764	$	100,351	$	2.66	41,639	$	76,044	$	1.83	(3,875	)	$	24,307		$	0.83	17,280	$	47,806	$	2.77	13,768	$	35,544	$	2.58	3,512		$	12,262		$	0.19
East Texas	12,752	36,078		2.83		18,933	39,607		2.09		(6,181	)	(3,529		)	0.74		2,648	6,991		2.64		3,736	9,716		2.60		(1,088	)	(2,725		)	0.04
South Texas	6,053	41,098		6.79		9,003	45,542		5.06		(2,950	)	(4,444		)	1.73		2,253	27,177		12.06		1,865	11,574		6.21		388		15,603			5.85
Appalachia and other	7,855	17,545		2.23		10,679	15,539		1.46		(2,824	)	2,006			0.77		4,861	11,566		2.38		2,465	4,395		1.78		2,396		7,171			0.60
Total	64,424	$	195,072	$	3.03	80,254	$	176,732	$	2.20	(15,830	)	$	18,340		$	0.83	27,042	$	93,540	$	3.46	21,834	$	61,229	$	2.80	5,208		$	32,311		$	0.66



	Nine Months Ended September 30,
	2018					2017					Period to period change
(dollars in thousands, except per unit rate)	Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)	Revenue		$/Mcfe		Production (Mmcfe)		Revenue			$/Mcfe
Producing region:
North Louisiana	54,398	$	151,204	$	2.78	37,764	$	100,351	$	2.66	16,634		$	50,853		$	0.12
East Texas	8,457	23,313		2.76		12,752	36,078		2.83		(4,295	)	(12,765		)	(0.07		)
South Texas	5,945	67,557		11.36		6,053	41,098		6.79		(108	)	26,459			4.57
Appalachia and other	13,224	29,388		2.22		7,855	17,545		2.23		5,369		11,843			(0.01		)
Total	82,024	$	271,462	$	3.31	64,424	$	195,072	$	3.03	17,600		$	76,390		$	0.28

Production for the three and nine months ended September 30, ~~2017decrease~~d2018 increased by ~~4.6~~5.2 Bcfe, or ~~17%~~23.9%, and ~~15.8~~17.6 Bcfe, or ~~20%~~27.3%, ~~respectively,~~ as compared ~~with~~to the same ~~periods~~period in ~~2016.~~2017. Significant components of the changes in production were a result of:

~~decreased~~Increased production of ~~0.9~~3.5 Bcfe and ~~3.9~~16.6 Bcfe for the three and nine months ended September 30, ~~2017,~~2018, respectively, in the North Louisiana region, primarily due to ~~production declines partially offset by additional volumes from the~~11 gross (6.7 net) operated wells turned-to-sales in the first quarter of 2018. There were no operated wells turned-to-sales in the first quarter of 2017 and 4 gross (3.5 net) operated wells turned-to-sales in second quarter of 2017. ~~We expect the production in the North Louisiana region to increase due to additional wells to be turned-to-sales during the fourth quarter of 2017.~~

~~decreased~~Decreased production of ~~2.6~~1.1 Bcfe and ~~6.2~~4.3 Bcfe for the three and nine months ended September 30, ~~2017,~~2018, respectively, in the East Texas region, primarily due to natural production declines as we have not turned an operated well to sales in the region since the first quarter of 2016.

Increased production of 0.4 Bcfe for the three months ended September 30, 2018 and decreased production of ~~0.7~~0.1 Bcfe for the nine months ended September 30, 2018 in the South Texas region. We turned-to-sales to 9 gross (8.6 net) operated wells in the first half of 2018. Prior to the first quarter of 2018, the most recent operated well turned-to-sales in this region was in the fourth quarter of 2015. During the three months ended September 30, 2018, our production was significantly impacted by wells shut-in as a result of nearby completion activity.

Increased production of 2.4 Bcfe and ~~3.0~~5.4 Bcfe for the three and nine months ended September 30, ~~2017, respectively, in the South Texas region, primarily due to production declines as we have not turned an operated well to sales in the region since late 2015.~~

~~decreased production of 0.5 Bcfe and 2.8 Bcfe for the three and nine months ended September 30, 2017,~~2018, respectively, in the Appalachia region, primarily due to the ~~sale~~acquisition of ~~our~~additional interests in ~~shallow conventional assets~~the Appalachia JV Settlement and 1 gross (0.9 net) operated well turned-to-sales in ~~2016 and production declines, partially offset by lower shut-in volumes. We have not had an active drilling program in this region since 2013. Production~~the first quarter of 2018. The last well that turned to sales in the Appalachia region ~~is expected~~prior to ~~be impacted by significant shut-in volumes during~~ the ~~fourth~~first quarter of ~~2017 due to low regional natural gas prices.~~2018 was in late 2015.

Oil and natural gas revenues for the three months ended September 30, ~~2017decrease~~d2018 increased by ~~$9.6~~$32.3 million, or ~~14%~~52.8%, as compared ~~with~~to the same period in ~~2016.~~2017. The ~~decrease~~increase in revenues was primarily ~~the result of lower oil and natural gas production, partially offset by~~due to an increase in production and higher oil and natural gas prices. Our average natural gas sales price increased 5%12.1% to $2.68 per Mcf for the three months ended September 30, 2018 from $2.39 per Mcf for the three months ended September 30, 2017, ~~from $2.27~~primarily due to higher market prices and improved natural gas differentials as a result of the rejection of certain executory contracts for the sale and marketing of natural gas in the North Louisiana region. Our average oil sales price per ~~Mcf~~Bbl increased 54.5% to $72.26 per Bbl for the three months ended September 30, ~~2016, primarily due to higher market prices. Our average sales price of oil per Bbl increased 13% to~~2018 from $46.76 ~~per Bbl for the~~

~~three months ended~~ ~~September 30, 2017~~ ~~from $41.47~~ per Bbl for the three months ended September 30, ~~2016~~,2017, primarily due to higher market prices.

Oil and natural gas revenues for the nine months ended September 30, ~~2017~~2018 increased by ~~$18.3~~$76.4 million, or ~~10%~~39.2%, as compared ~~with~~to the same period in ~~2016.~~2017. The increase in revenues was primarily the result of an increase in oil prices and ~~natural gas prices partially offset by lower oil and natural gas~~an increase in production. Our average natural gas sales price increased ~~45%~~4.3% to $2.68 per Mcf for the nine months ended September 30, 2018 from $2.57 per Mcf for the nine months ended September 30, 2017, ~~from $1.77 per Mcf for the nine months ended September 30, 2016,~~ primarily due to ~~higher market prices.~~improved natural gas price differentials as a result of the rejection of certain executory contracts for the sale and marketing of natural gas in the North Louisiana region. Our average sales price of oil per Bbl increased ~~33%~~43.8% to $68.61 per Bbl for the nine months ended September 30, 2018 from $47.70 per Bbl for the nine months ended September 30, 2017, ~~from $35.80 per Bbl for the nine months ended September 30, 2016,~~ primarily due to higher market prices.

Purchased natural gas and marketing revenues

Purchased natural gas and marketing revenues include revenues we receive as a result of selling natural gas purchased from third parties and marketing fees we receive from third parties. Purchased natural gas and marketing revenues for the three months ended September 30, ~~2017~~2018 decreased by ~~$0.8~~$0.5 million, or ~~13%~~8.6%, as compared ~~with~~to the same period in ~~2016. The decrease was primarily due to lower volumes purchased, partially offset by higher marketing fees charged to third parties beginning in September 2016.~~2017. Purchased natural gas and marketing revenues for the nine months ended September 30, ~~2017 increased~~2018 decreased by ~~$3.9~~$3.5 million, or ~~25%~~18.2%, ~~respectively,~~ as compared ~~with~~to the same period in ~~2016.~~2017. The ~~increase~~decrease for the three and nine months ended September 30, 2018 was primarily due to ~~higher natural gas prices and~~lower marketing fees charged to third parties ~~beginning in September 2016, partially offset by~~and lower volumes purchased. The decrease in marketing fees charged to third parties was primarily due to an increase in our average working interests in production from operated wells compared to the

same period in prior year.

Oil and natural gas operating costs

The following tables present our oil and natural gas operating costs for the three and nine months ended September 30, ~~2017~~2018 and ~~2016:~~2017:


	Three Months Ended September 30,																					Three Months Ended September 30,
	2017						2016						Quarter to quarter change									2018						2017						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	$	3,582	$	1,917	$	5,499	$	2,841	$	341	$	3,182	$	741		$	1,576		$	2,317		$	4,741	$	1,789	$	6,530	$	3,582	$	1,917	$	5,499	$	1,159		$	(128	)	$	1,031
East Texas	1,049		17		1,066		1,482		23		1,505		(433		)	(6		)	(439		)	840		977		1,817		1,049		17		1,066		(209		)	960			751
South Texas	2,303		2		2,305		2,937		—		2,937		(634		)	2			(632		)	3,650		6		3,656		2,303		2		2,305		1,347			4			1,351
Appalachia and other	345		—		345		1,131		42		1,173		(786		)	(42		)	(828		)	810		197		1,007		345		—		345		465			197			662
Total	$	7,279	$	1,936	$	9,215	$	8,391	$	406	$	8,797	$	(1,112	)	$	1,530		$	418		$	10,041	$	2,969	$	13,010	$	7,279	$	1,936	$	9,215	$	2,762		$	1,033		$	3,795

	Three Months Ended September 30,																					Three Months Ended September 30,
	2017						2016						Quarter to quarter change									2018						2017						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	$	0.26	$	0.14	$	0.40	$	0.19	$	0.02	$	0.21	$	0.07		$	0.12		$	0.19		$	0.27	$	0.10	$	0.37	$	0.26	$	0.14	$	0.40	$	0.01		$	(0.04	)	$	(0.03	)
East Texas	0.28		—		0.28		0.23		—		0.23		0.05			—			0.05			0.32		0.37		0.69		0.28		—		0.28		0.04			0.37			0.41
South Texas	1.23		—		1.23		1.17		—		1.17		0.06			—			0.06			1.62		—		1.62		1.23		—		1.23		0.39			—			0.39
Appalachia and other	0.14		—		0.14		0.38		0.01		0.39		(0.24		)	(0.01		)	(0.25		)	0.17		0.04		0.21		0.14		—		0.14		0.03			0.04			0.07
Total	$	0.33	$	0.09	$	0.42	$	0.32	$	0.01	$	0.33	$	0.01		$	0.08		$	0.09		$	0.37	$	0.11	$	0.48	$	0.33	$	0.09	$	0.42	$	0.04		$	0.02		$	0.06


	Nine Months Ended September 30,																					Nine Months Ended September 30,
	2017						2016						Period to period change									2018						2017						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	$	10,000	$	2,333	$	12,333	$	8,421	$	493	$	8,914	$	1,579		$	1,840		$	3,419		$	13,348	$	2,014	$	15,362	$	10,000	$	2,333	$	12,333	$	3,348		$	(319	)	$	3,029
East Texas	3,476		814		4,290		3,746		229		3,975		(270		)	585			315			2,692		1,627		4,319		3,476		814		4,290		(784		)	813			29
South Texas	8,052		4		8,056		8,506		246		8,752		(454		)	(242		)	(696		)	9,120		77		9,197		8,052		4		8,056		1,068			73			1,141
Appalachia and other	1,241		8		1,249		4,152		42		4,194		(2,911		)	(34		)	(2,945		)	2,486		428		2,914		1,241		8		1,249		1,245			420			1,665
Total	$	22,769	$	3,159	$	25,928	$	24,825	$	1,010	$	25,835	$	(2,056	)	$	2,149		$	93		$	27,646	$	4,146	$	31,792	$	22,769	$	3,159	$	25,928	$	4,877		$	987		$	5,864

	Nine Months Ended September 30,																					Nine Months Ended September 30,
	2017						2016						Period to period change									2018						2017						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	$	0.26	$	0.06	$	0.32	$	0.20	$	0.01	$	0.21	$	0.06		$	0.05		$	0.11		$	0.25	$	0.04	$	0.29	$	0.26	$	0.06	$	0.32	$	(0.01	)	$	(0.02	)	$	(0.03	)
East Texas	0.27		0.06		0.33		0.20		0.01		0.21		0.07			0.05			0.12			0.32		0.19		0.51		0.27		0.06		0.33		0.05			0.13			0.18
South Texas	1.33		—		1.33		0.94		0.03		0.97		0.39			(0.03		)	0.36			1.53		0.01		1.54		1.33		—		1.33		0.20			0.01			0.21
Appalachia and other	0.16		—		0.16		0.39		—		0.39		(0.23		)	—			(0.23		)	0.19		0.03		0.22		0.16		—		0.16		0.03			0.03			0.06
Total	$	0.35	$	0.05	$	0.40	$	0.31	$	0.01	$	0.32	$	0.04		$	0.04		$	0.08		$	0.34	$	0.05	$	0.39	$	0.35	$	0.05	$	0.40	$	(0.01	)	$	—		$	(0.01	)

Oil and natural gas operating costs for the three and nine months ended September 30, ~~2017~~2018 increased by ~~$0.4~~$3.8 million and $5.9 million, or 5%41.2% and 22.6%, respectively as compared to the same period in ~~2016,~~2017, primarily due to higher ~~oil~~variable costs as a result of increased production and ~~natural gas operating costs in~~ the ~~North Louisiana region primarily due to an increase in workover activity and additional producing wells as compared to prior period. This was partially offset by the sale~~acquisition of ~~our conventional assets~~Shell’s interests in the Appalachia ~~region during 2016. Oil and natural gas operating costs for the~~

nine months ended September 30, 2017 remained consistent with the same period in 2016. Higher workover expenses and higher oil and natural gas operating costs in the North Louisiana region from additional producing wells during the nine months ended September 30, 2017 were offset by lower lease operating expenses in the Appalachia region primarily due to the sale of our conventional assets during 2016.

JV Settlement. Oil and natural gas operating costs increased from ~~$0.33 per Mcfe for the three months ended September 30, 2016 to~~ $0.42 per Mcfe for the three months ended September 30, ~~2017.~~2017 to $0.48 per Mcfe for the three months ended September 30, 2018. The increase on a per Mcfe basis was primarily due to higher preventative maintenance costs associated with offset completion activities. Oil and natural gas operating costs ~~increased~~decreased from ~~$0.32 per Mcfe for the nine months ended September 30, 2016 to~~ $0.40 per Mcfe for the nine months ended September 30, ~~2017.~~2017 to $0.39 per Mcfe for the nine months ended September 30, 2018. The ~~increases were~~decrease on a per Mcfe basis was primarily due to ~~declining production.~~increased production in relation to certain fixed oil and natural gas operating costs.

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, ~~2017~~2018 and ~~2016:~~

Three Months Ended September 30,
2017 2016
(in thousands, except per unit rate) Production and ad valorem taxes % of revenue Taxes $/Mcfe Production and ad valorem taxes % of revenue Taxes $/Mcfe
Producing region:
North Louisiana $ 1,916
5.4 % $ 0.14
$ 1,627
4.7 % $ 0.11
East Texas 176
1.8 % 0.05
277
1.7 % 0.04
South Texas 775
6.7 % 0.42
1,626
10.9 % 0.65
Appalachia and other 177
4.0 % 0.07
281
6.1 % 0.09
Total $ 3,044
5.0 % $ 0.14
$ 3,811
5.4 % $ 0.14
2017:


	Nine Months Ended September 30,												Three Months Ended September 30,
	2017						2016						2018						2017
(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	$	5,174	5.2	%	$	0.14	$	5,909	7.8	%	$	0.14	$	1,627	3.4	%	$	0.09	$	1,916	5.4	%	$	0.14
East Texas	801		2.2	%	0.06		864		2.2	%	0.05		114		1.6	%	0.04		176		1.8	%	0.05
South Texas	3,473		8.5	%	0.57		5,903		13.0	%	0.66		2,145		7.9	%	0.95		775		6.7	%	0.42
Appalachia and other	446		2.5	%	0.06		632		4.1	%	0.06		420		3.6	%	0.09		177		4.0	%	0.07
Total	$	9,894	5.1	%	$	0.15	$	13,308	7.5	%	$	0.17	$	4,306	4.6	%	$	0.16	$	3,044	5.0	%	$	0.14



	Nine Months Ended September 30,
	2018						2017
(in thousands, except per unit rate)	Production and ad valorem taxes		% of revenue		Taxes $/Mcfe		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe
Producing region:
North Louisiana	$	5,069	3.4	%	$	0.09	$	5,174	5.2	%	$	0.14
East Texas	682		2.9	%	0.08		801		2.2	%	0.06
South Texas	5,045		7.5	%	0.85		3,473		8.5	%	0.57
Appalachia and other	1,587		5.4	%	0.12		446		2.5	%	0.06
Total	$	12,383	4.6	%	$	0.15	$	9,894	5.1	%	$	0.15

Production and ad valorem taxes for the three months ended September 30, 2017 decreased by $0.8 million, or 20%, as compared with the same period in 2016. The decrease was primarily due to lower ad valorem taxes in South Texas primarily due to lower appraised values. Production and ~~ad valorem taxes for the~~ nine months ended September 30, ~~2017 decreased~~2018 increased by ~~$3.4~~$1.3 million and $2.5 million or ~~26%~~41.5% and 25.2%, respectively, as compared ~~with~~to the same period in ~~2016.~~2017. The ~~decrease~~increase was primarily due to ~~lower ad valorem taxes~~an increase in ~~South Texas~~oil prices of 54.5% and ~~lower production taxes primarily~~43.8%, respectively, for the three and nine months ended September 30, 2018. The increase in North Louisiana due to a decrease in volumes and lower severance tax rates in Louisiana, which decreased from $0.158 per Mcf to $0.098 per Mcf in July 2016. In July 2017, the effective severance tax rate increased to $0.111 per Mcf. The decrease was partially offset by higher commodity prices. The higher commodityoil prices primarily impacted properties located in our South Texas region because production taxes are based on a fixed percentage of gross value of production sold. In addition, we incurred higher assessments for the impact fee required to be paid to the Commonwealth of Pennsylvania. The increase in the impact fee was primarily due to higher natural gas market prices and the additional interests in oil and natural gas properties acquired as a result of the Appalachia JV Settlement.

Gathering and transportation

Gathering and transportation expenses for the three months ended September 30, ~~2017 increased~~2018 decreased by ~~$0.8~~$9.5 million, or 3%33.2%, as compared ~~with~~to the same period in ~~2016.~~2017. Gathering and transportation expenses for the nine months ended September 30, ~~2017 increased~~2018 decreased by ~~$3.4~~$22.7 million, or 4%27.3%, as compared ~~with~~to the same period in 2016. The increase for the nine months ended September 30, 2017 was primarily due to gathering expenses in connection with taking our gas in-kind from certain third-party operated wells in the North Louisiana region during 2016, higher variable gathering costs on volumes from wells turned-to-sales in North Louisiana during the second half of 2016 and 2017, and 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. The increase is partially offset by lower gathering and transportation expenses in all regions due to lower production.2017. Gathering and transportation expenses were ~~$1.32~~$0.71 per Mcfe for the three months ended September 30, ~~2017~~2018 as compared to ~~$1.06~~$1.32 per Mcfe for the same period in ~~2016.~~2017. Gathering and transportation expenses were ~~$1.29~~$0.74 per Mcfe for the nine months ended September 30, ~~2017~~2018 as compared to ~~$0.99~~$1.29 per Mcfe for the same period in ~~2016.~~2017. The ~~increases~~decreases were primarily due to ~~lower volumes in relation to fixed costs under gathering and firm~~the impact of the rejection of executory contracts for the transportation ~~contracts~~of natural gas in the ~~East Texas and~~ North Louisiana ~~regions.~~region that occurred in the first quarter of 2018.

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 and nine months ended September 30, ~~2017~~2018 decreased by ~~$1.2~~$1.6 million and $6.6 million or ~~18%~~29.9% and 36.1%, respectively, as compared ~~with~~to the same period in ~~2016.~~2017. The decrease was primarily due to lower volumes ~~purchased. Purchased~~purchased and lower transportation costs as a result of the rejection of executory contracts for the transportation of natural gas ~~expenses increased by $0.9 million, or 5%, as compared with~~in the ~~same periods in 2016. The increase was primarily due to higher purchase prices partially offset by lower volumes purchased.~~North Louisiana region.

Depletion, depreciation and amortization

Depletion, depreciation and amortization for the three and nine months ended September 30, ~~2017 decreased~~2018 increased from the same period in ~~2016~~2017 primarily due to ~~a decrease~~an increase in depletion expense of ~~$2.2~~$7.0 million and $24.0 million, or ~~14%.~~52.3% and 66.9%, respectively. The ~~decrease~~increase in depletion expense was primarily due to ~~a decrease~~an increase in ~~production.~~production and higher depletion rate. On a per Mcfe basis, the depletion rate for the three months ended September 30, ~~2017~~2018 was ~~$0.61~~$0.75 per Mcfe, compared ~~with $0.59~~to $0.61 per Mcfe in the same period in ~~2016.~~

~~Depletion, depreciation and amortization for the nine months ended September 30, 2017 decreased from the same period in 2016 primarily due to a decrease in depletion expense of $27.0 million, or 43%.~~2017. The ~~decrease in depletion expense was primarily due to a decrease in production and the depletion rate. On a per Mcfe basis, the~~ depletion rate for the nine months ended September 30, ~~2017~~2018 was ~~$0.56~~$0.73 per Mcfe, compared ~~with $0.78~~to $0.56 per Mcfe in the same period in ~~2016.~~2017. The ~~decrease~~increase in the depletion rate was primarily due to ~~an increase~~the additional costs associated with our development of the South Texas and North Louisiana regions. In particular, the development of oil producing assets in South Texas results in a higher depletion rate when calculated on per Mcfe basis compared to the rest of our ~~total proved reserves due to an increase in commodity prices.~~properties.

Impairment of oil and natural gas properties

We did not record an impairment to our oil and natural gas properties for the three ~~months ended September 30, 2017 and 2016,~~ and nine months ended September 30, 2017. We recorded impairments of $160.8 million for the nine months ended September 30, 2016. The impairments for the nine months ended September 30, 2016 were primarily due to the significant decline in oil2018 and ~~natural gas prices.~~2017. The possibility and amount of any future impairment is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

General and administrative

The following table presents our general and administrative expenses for the three and nine months ended September 30, ~~2017~~2018 and ~~2016:~~2017:


	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands)	2017			2016			Quarter to quarter change			2017			2016			Period to period change			2018			2017			Quarter to quarter change			2018			2017			Period to period change
General and administrative expenses:
Gross general and administrative expenses	$	17,040		$	14,863		$	2,177		$	41,826		$	42,635		$	(809	)	$	10,666		$	17,040		$	(6,374	)	$	35,606		$	41,826		$	(6,220	)
Technical services and service agreement charges	(1,675		)	(1,312		)	(363		)	(4,573		)	(5,705		)	1,132			(913		)	(1,675		)	762			(3,336		)	(4,573		)	1,237
Operator overhead reimbursements	(3,782		)	(3,463		)	(319		)	(10,860		)	(10,339		)	(521		)	(3,494		)	(3,782		)	288			(10,527		)	(10,860		)	333
Capitalized salaries	(682		)	(759		)	77			(2,130		)	(2,523		)	393			(678		)	(682		)	4			(2,253		)	(2,130		)	(123		)
General and administrative expenses, excluding equity-based compensation	10,901			9,329			1,572			24,263			24,068			195			5,581			10,901			(5,320		)	19,490			24,263			(4,773		)
Gross equity-based compensation	(707		)	1,642			(2,349		)	(10,355		)	14,990			(25,345		)	565			(707		)	1,272			1,770			(10,355		)	12,125
Capitalized equity-based compensation	(159		)	(225		)	66			(852		)	(432		)	(420		)	(31		)	(159		)	128			(315		)	(852		)	537
General and administrative expenses	$	10,035		$	10,746		$	(711	)	$	13,056		$	38,626		$	(25,570	)	$	6,115		$	10,035		$	(3,920	)	$	20,945		$	13,056		$	7,889

General and administrative expenses for the three months ended September 30, ~~2017~~2018 decreased by ~~$0.7~~$3.9 million ~~or 7%,~~ compared ~~with~~to the same period in ~~2016.~~2017. General and administrative expenses for the nine months ended September 30, ~~2017 decreased~~2018 increased by ~~$25.6~~$7.9 million ~~or 66%,~~ compared ~~with~~to the same period in ~~2016.~~2017. Significant components of the changes in general and administrative expenses were a result of:

~~decreased~~

Higher equity-based compensation of ~~$2.3~~$1.4 million and ~~$25.8~~$12.7 million for the three and nine months ended September 30, ~~2017, respectively. The decrease was~~2018, primarily due to income in prior year of $1.3 million and $15.0 million, respectively, related to a significant decline in the fair value of the warrants issued to ~~ESAS~~Energy Strategic Advisory Services LLC (“ESAS”). This was partially offset by a decrease in ~~connection with the ESAS services and investment agreement ("ESAS Warrants") that resulted in income~~equity-based compensation of ~~$1.3 million and $14.2~~$2.8 million for the ~~three and~~ nine months ended September 30, ~~2017, respectively, as compared~~2018 due to ~~expense~~the discontinuation of ~~$0.9~~grants of share-based compensation to employees and lower employee headcount.

Increased personnel costs of $3.6 million ~~and $11.8 million~~ for ~~the three and~~ nine months ended September 30, ~~2016, respectively.~~2018. The fair value of the ESAS Warrants is dependent on factors such as our share price, historical volatility, risk-free rate and performance relative to our peer group. The decrease in EXCO's share price contributed to a significant decrease in the fair value of the ESAS Warrants and the related equity-based compensation expense at September 30, 2017. The expense related to ESAS Warrants is re-measured and adjusted each interim reporting period; therefore, our general and administrative expenses in future periods could be volatile based on the aforementioned factors.

~~increased personnel costs of $2.0 million for the three months ended September 30, 2017,~~increase was primarily due to higher bonus expense during the current ~~period,~~year, partially offset by ~~the reductions in our workforce.~~lower headcount. The increase in bonus expense was due to the adoption of new cash-based retention and incentive plans ~~during the three months ended September 30, 2017.~~in connection with our restructuring activities. The cash-based retention and incentive plans are intended to replace grants under the equity-based incentive plans. As a result, ~~we expect~~ cash-based personnel costs ~~to increase~~increased and equity-based compensation ~~to decrease in future periods. Additional information on the new cash-based retention and incentive plans is included in the Form 8-K filed with the SEC on October 10, 2017.~~expense decreased.

~~decreased~~Decreased consulting and contract labor costs of ~~$0.7~~$0.8 million and ~~$1.5~~$2.4 million for the three and nine months ended September 30, ~~2017,~~2018, respectively, primarily ~~related~~due to the ~~changes in our accrual for~~suspension of the ~~annual incentive payment to~~services and investment agreement with ESAS that ~~is based on EXCO’s common share price achieving certain performance hurdles as compared to a peer group.~~was effective November 9, 2017.

~~increased~~Decreased legal and professional ~~and legal~~ fees of ~~$0.9~~$4.2 million and ~~$3.1~~$4.7 million for the three and nine months ended September 30, ~~2017, respectively, primarily related to various~~2018, respectively. Our legal and ~~advisory fees. As discussed in "Note 1. Organization and basis~~professional fees during 2017 primarily consisted of ~~presentation" in the Notes to our Condensed Consolidated Financial Statement, we hired~~legal, financial and restructuring advisors engaged to ~~explore~~evaluate strategic ~~alternatives~~alternatives. Any legal and professional fees incurred subsequent to ~~strengthen our balance sheet and maximize~~ the ~~value of the Company. Based~~Petition Date are classified as “Reorganization items, net” on the ~~terms~~Condensed Consolidated Statement of Operations.

Decreased overhead reimbursement, technical services and service agreement charges of $1.1 million and $1.6 million for the three and nine months ended September 30, 2018, respectively. The decreases are primarily a result of lower recoveries from third parties due to the acquisition of our joint venture partner’s interests in the Appalachia JV Settlement.

Decreased information technology costs of $0.5 million and $1.0 million for the three and nine months ended September 30, 2018, respectively. The decreases are primarily due to the renegotiation of certain of our debt agreements, we are required to pay costs related to legal and financial advisors of debtholders in connection with the restructuring process. Furthermore, we have agreed to pay costs related to legal and financial advisors of certain other debtholders in order to facilitate our restructuring process. As a result, we expect professional and legal fees to increase in future periods.software licensing agreements.

~~decreased~~Decreased various other gross general and administrative expenses of ~~$2.4~~$0.9 million and $1.9 million for the three and nine months ended September 30, ~~2017.~~2018, respectively. These decreases reflect our continued efforts to reduce our general and administrative ~~costs throughout the organization.~~costs.

~~decreased technical services and service agreement recoveries of $1.1 million for the nine months ended September 30, 2017, primarily a result of reduced headcount.~~

~~Other operating items~~

Other operating items were a net loss of $1.7 million and a net gain of $1.1 million for the three months ended September 30, 2017 and 2016, respectively. Other operating items were net losses of $3.1 million and $23.9 million for the nine months ended September 30, 2017 and 2016, respectively. The net losses for the three and nine months ended September 30, 2017 were primarily related to the impairments of certain assets. The net loss for the nine months ended September 30, 2016 was primarily due to the settlement of the litigation with a joint venture partner.

Interest expense, net

~~The following table presents our interest expense, net for the three and nine months ended~~ ~~September 30, 2017~~ ~~and~~ ~~2016~~:

Three Months Ended September 30, Nine Months Ended September 30,
(in thousands) 2017 2016 Quarter to quarter change 2017 2016 Period to period change
Interest expense, net:
EXCO Resources Credit Agreement $ 813
$ 1,585
$ (772 ) $ 3,008
$ 3,890
$ (882 )
1.5 Lien Notes 12,117
—
12,117
26,039
—
26,039
1.75 Lien Term Loans 15,447
—
15,447
23,011
—
23,011
Fairfax Term Loan —
9,375
(9,375 ) 7,708
28,125
(20,417 )
2018 Notes 2,540
2,571
(31 ) 7,616
8,076
(460 )
2022 Notes 1,491
2,512
(1,021 ) 4,473
10,819
(6,346 )
Amortization of deferred financing costs 2,140
2,184
(44 ) 7,864
7,052
812
Capitalized interest (1,729 ) (1,297 ) (432 ) (4,627 ) (3,939 ) (688 )
Other 69
67
2
228
163
65
Total interest expense, net $ 32,888
$ 16,997
$ 15,891
$ 75,320
$ 54,186
$ 21,134

Interest expense, net for the three and nine months ended September 30, ~~2017 increased $15.9~~2018 decreased $23.9 million and ~~$21.1~~$49.3 million, respectively, from the same periods in ~~2016.~~2017. The ~~increases~~decreases were primarily due to ~~additional~~the suspension of interest ~~expense~~accrued on certain instruments subsequent to the Petition Date. As a result of the bankruptcy proceedings, the Court limited post-petition interest on certain indebtedness that may be under-secured or unsecured. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We continued to accrue and pay interest on the DIP Credit Agreement and the 1.5 Lien Notes ~~and~~subsequent to the Petition Date. We accrued interest on 1.75 Lien Term Loans, ~~partially as a result of higher interest rates associated with PIK Payments. This was partially offset by lower interest expense on the~~Second Lien Term Loans, 2018 Notes and 2022 Notes ~~due~~through the Petition Date with no interest accrued subsequent to ~~lower outstanding balances as a result of note repurchases that occurred during 2016, lower average outstanding balances on~~ the ~~EXCO Resources Credit Agreement and the Fairfax Term Loan. The Fairfax Term Loan was terminated as a result of the Second Lien Term Loan Exchange.~~

~~As discussed in "Note~~Petition Date. See “Note 8. ~~Debt"~~Debt” in the Notes to our Condensed Consolidated Financial Statements the combined fair value of the warrants issued of $148.6 million as of March 15, 2017 and $4.5 million of cash paid to certain investors who elected to receive cash in lieu of warrants was recorded as a discount to the 1.5 Lien Notes. In addition, the combined fair value of the warrants issued of $12.6 million and $8.6 million of cash paid to the lenders who elected to receive cash in lieu of warrants was recorded as a discount to the 1.75 Lien Term Loans. As such, we expect our interest expense to continue to increase in future periods due the significant discount balances that are being amortized to interest expense over the life of the loans. In addition, any future PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans could increase our interest expense due to higher interest rates associated with PIK Payments.for additional information.

The Exchange Term Loan, as defined in "Note 8. Debt" in the Notes to our Condensed Consolidated Financial Statements, and a portion of the 1.75 Lien Term Loans are accounted for as a troubled debt restructuring pursuant to Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 470-60, ~~Troubled Debt Restructuring by Debtors~~. As such, the carrying amounts of the Exchange Term Loan and a portion of the 1.75 Lien Term Loans, whether designated as interest or as principal amount, are adjusted each time we make a payment. Interest expense is recognized on this portion of the 1.75 Lien Term Loans if the fair value of the PIK Payments exceeds the interest capitalized as part of the carrying value.

Gain (loss) on derivative financial instruments - commodity derivatives

~~Our oil and natural gas derivative financial instruments resulted in net gains of $0.9 million and $8.2 million for the three months ended September 30, 2017 and 2016, respectively.~~

Our oil and natural gas derivative financial instruments resulted in a net gain of ~~$22.9~~$0.9 million for the three months ended September 30, 2017. Our oil and natural gas derivative financial instruments resulted in a net loss of $0.6 million and a net ~~loss~~gain of ~~$11.6~~$22.9 million for the nine months ended September 30, 2018 and 2017, ~~and 2016,~~ respectively. ~~Based on~~In January 2018, the ~~nature of~~counterparty to our ~~derivative~~remaining open swap contracts ~~increases in~~early terminated the ~~related commodity price typically~~outstanding contracts effective January 31, 2018. As a result, ~~in a decrease to the value of our derivative contracts. The significant fluctuations demonstrate the high volatility in~~we did not have any outstanding 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.~~subsequent to the termination of these contracts.

The following table presents our oil and natural gas prices, before and after the impact of the cash settlement of our commodity derivatives:


	Three Months Ended September 30,							Nine Months Ended September 30,								Three Months Ended September 30,							Nine Months Ended September 30,
Average realized pricing:	2017		2016		Quarter to quarter change			2017			2016		Period to period change			2018		2017		Quarter to quarter change			2018		2017			Period to period change
Natural gas (per Mcf):
Net price, excluding derivatives	$	2.39	$	2.27	$	0.12		$	2.57		$	1.77	$	0.80		$	2.68	$	2.39	$	0.29		$	2.68	$	2.57		$	0.11
Cash receipts (payments) on derivatives	0.03		0.04		(0.01		)	(0.09		)	0.34		(0.43		)	—		0.03		(0.03		)	0.01		(0.09		)	0.10
Net price, including derivatives	$	2.42	$	2.31	$	0.11		$	2.48		$	2.11	$	0.37		$	2.68	$	2.42	$	0.26		$	2.69	$	2.48		$	0.21
Oil (per Bbl):
Net price, excluding derivatives	$	46.76	$	41.47	$	5.29		$	47.70		$	35.80	$	11.90		$	72.26	$	46.76	$	25.50		$	68.61	$	47.70		$	20.91
Cash receipts (payments) on derivatives	0.30		9.65		(9.35		)	0.08			9.93		(9.85		)	—		0.30		(0.30		)	—		0.08			(0.08		)
Net price, including derivatives	$	47.06	$	51.12	$	(4.06	)	$	47.78		$	45.73	$	2.05		$	72.26	$	47.06	$	25.20		$	68.61	$	47.78		$	20.83
Natural gas equivalent (per Mcfe):
Net price, excluding derivatives	$	2.80	$	2.68	$	0.12		$	3.03		$	2.20	$	0.83		$	3.46	$	2.80	$	0.66		$	3.31	$	3.03		$	0.28
Cash receipts (payments) on derivatives	0.03		0.18		(0.15		)	(0.08		)	0.47		(0.55		)	—		0.03		(0.03		)	0.01		(0.08		)	0.09
Net price, including derivatives	$	2.83	$	2.86	$	(0.03	)	$	2.95		$	2.67	$	0.28		$	3.46	$	2.83	$	0.63		$	3.32	$	2.95		$	0.37

Our total cash ~~receipts~~payments for the three months ended September 30, 2017 were $0.6 million, or $0.03 per ~~Mcfe, compared to $4.7 million, or $0.18 per Mcfe, for the three months ended September 30, 2016.~~Mcfe. Our total cash ~~payments~~receipts for the nine months ended September 30, ~~2017~~2018 were ~~$5.0~~$0.5 million, or ~~$0.08~~$0.01 per Mcfe, compared to cash ~~receipts~~payments of ~~$38.1~~$5.0 million, or ~~$0.47~~$0.08 per Mcfe, for the nine months ended September 30, ~~2016. As noted above, the significant fluctuations between settlements on our derivative financial instruments demonstrate the volatility in commodity prices.~~2017.

Gain on derivative financial instruments - common share warrants

Pursuant to FASB ASC Topic 815, Derivatives and Hedging, ("(“ASC ~~815"~~815”), we account for the ~~warrants issued in connection with the issuance of the 1.5 Lien Notes and 1.75 Lien Term Loans~~2017 Warrants as derivative financial instruments and carry the warrants as a non-current liability at their fair value, with the increase or decrease in fair value being recognized in earnings. These warrants are measured at fair value on a recurring basis until the date of exercise or the date of expiration. WeOn January 16, 2018, affiliates of Fairfax surrendered all of their rights to the 2017 Warrants, which had entitled them rights to purchase in aggregate up to 10,824,376 common shares at $13.95 per share and 1,725,576 common shares at $0.01 per share. During the three and nine months ended September 30, 2018, we recorded a ~~gain on the revaluation~~loss of ~~the warrants of $18.3~~$0.3 million and ~~$146.6~~a gain $1.4 million, ~~during~~respectively, primarily due to the cancellation of warrants by Fairfax and changes in EXCO’s share price. During the three and nine months ended September 30, 2017, we recorded gains of $18.3 million and $146.6 million, respectively, primarily due to a decrease in ~~EXCO's~~EXCO’s share price.

~~Gain (loss)~~Reorganization items, net

Pursuant to ASC 852, any costs directly related to an entity’s bankruptcy proceedings are presented separately as reorganization items. We recorded a net loss on reorganization items of $18.2 million for the three months ended September 30, 2018, which was comprised of $3.0 million related to the rejection of the office lease for our corporate headquarters and $15.2 million of legal and professional fees related to the bankruptcy proceedings. We recorded a net loss on reorganization items of $387.5 million for the nine months ended September 30, 2018 primarily due to the rejection of executory contracts of $312.2 million, legal and professional fees of $44.8 million and the acceleration of deferred financing costs, debt discounts and deferred reductions in carrying value of debt instruments of $30.5 million. The losses associated with the rejection of executory contracts and adjustments to the carrying value of debt instruments are based on our current estimate of the allowable claims and may differ from actual claims or future settlement amounts paid. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material. See “Note 1. Organization and basis of presentation” in the Notes to our Condensed Consolidated Financial Statements for additional information.

Loss on restructuring and extinguishment of debt

For the nine months ended September 30, 2017, we recorded a loss on restructuring of debt of $6.4 million related to the transaction costs associated with the exchange of Second Lien Term Loan Exchange transaction costs. For the three and nine months ended September 30, 2016, we recorded a net gain on extinguishment of debt of $57.4 million and $119.4 million, respectively. The net gainsLoans for ~~the three and nine months ended September 30, 2016 were primarily due to the repurchases of the 2018 Notes and 2022 Notes.~~1.75 Lien Term Loans.

Equity income

Equity income ~~(loss)~~

~~Our equity income (loss)~~ was ~~net income of~~ $0.4 ~~million and a net loss of $0.8~~ million for the three months ended September 30, ~~2017 and 2016, respectively. Our equity~~2017. Equity income ~~(loss)~~ was ~~net income of $1.0~~$0.2 million and ~~a net loss of $8.8~~$1.0 million for the nine months ended September 30, 2018 and 2017, respectively. We acquired the remaining ownership interests in OPCO and ~~2016, respectively. The increase~~Appalachia Midstream as a result of the Appalachia JV Settlement on February 27, 2018. Prior to the settlement, we accounted for our ownership interests in OPCO and Appalachia Midstream as equity ~~earnings is due to higher earnings from~~method investments. As a result of the settlement, OPCO and Appalachia Midstream are wholly owned subsidiaries and are consolidated within our ~~investment that serves as~~financial results.

Income taxes

During the ~~operator and owns an interest in our Appalachia assets. The equity loss for the nine~~three months ended September 30, ~~2016 was primarily due to a $4.9 million impairment of our midstream investment in the East Texas and North Louisiana regions that~~2018, we account for under the cost method of accounting. 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~~

did not recognize any income tax expense. During the three months ended September 30, 2017, ~~and 2016,~~ we recognized income tax expense of $0.3 ~~million and $1.0 million, respectively.~~million. During the nine months ended September 30, ~~2017~~2018 and ~~2016,~~2017, we recognized an income tax benefit of $4.5 million and income tax expense of $2.4 ~~million and $1.8~~ million, respectively. The following table presents our income tax benefit and expense for the three and nine months ended September 30, ~~2017~~2018 and ~~2016~~:2017:

Three Months Ended September 30, Nine Months Ended September 30,
(in thousands) 2017 2016 Quarter to quarter change 2017 2016 Period to period change
Income tax expense:
Current income tax benefit $ (709 ) $ —
$ (709 ) $ (709 ) $ —
$ (709 )
Deferred income tax expense 1,028
1,028
—
3,083
1,775
1,308
Total income tax expense $ 319
$ 1,028
$ (709 ) $ 2,374
$ 1,775
$ 599



	Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)	2018		2017			Quarter to quarter change			2018			2017			Period to period change
Income tax (benefit) expense:
Current income tax (benefit) expense	$	—	$	(709	)	$	709		$	—		$	(709	)	$	709
Deferred income tax (benefit) expense	—		1,028			(1,028		)	(4,518		)	3,083			(7,601		)
Total income tax (benefit) expense	$	—	$	319		$	(319	)	$	(4,518	)	$	2,374		$	(6,892	)

~~Current~~

Deferred income tax benefit during the ~~three and~~ nine months ended September 30, ~~2017~~2018 related to ~~refundable alternative minimum tax credits. Deferred income tax expense recognized~~changes in ~~all periods related to~~ a deferred tax liability for tax-deductible goodwill. As of December 31, 2017, we recognized a deferred tax liability of $4.5 million for tax-deductible goodwill. The deferred tax liability related to goodwill iswas considered to have an indefinite life based on the nature of the underlying asset and ~~cannot~~could not be offset under GAAP with a deferred tax asset with a definite life, such as net operating loss carryforwards ~~("NOLs"~~(“NOLs”). ~~However,~~As a result of the Tax Cuts and Jobs Act (“Tax Act”), deferred tax assets resulting from NOLs generated in taxable years subsequent to December 31, 2017 are considered to have an indefinite life. Therefore, we recognized an income tax benefit of $4.5 million during the three months ended March 31, 2018 because we expect to be able to utilize deferred tax assets related to NOLs to offset the deferred tax liability related to goodwill. We recognized deferred income tax expense ~~is not expected to result in cash payments~~ of ~~income taxes~~$0.3 million and $3.1 million during the three and nine months ended September 30, 2017, respectively, for changes in the ~~foreseeable future.~~deferred tax liability related to tax-deductible goodwill with an indefinite life that could not be offset by NOLs that were considered to have a definite life prior to the enactment of the Tax Act.

Our net deferred tax assets ~~excluding the deferred tax liability for goodwill,~~ have been fully reserved with valuation allowances. Our accumulated valuation allowance as of September 30, ~~2017~~2018 was approximately ~~$1.3 billion~~$880.9 million and has fully offset our net deferred tax ~~assets, excluding the deferred tax liability for goodwill.~~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 Second Lien Term Loan Exchange, we had cancellation of debt income for tax purposes that reduced our NOLs by $86.6 million during the nine months ended September 30, 2017.~~

The effective income tax rates, excluding the impact of the valuation allowances, would have been 73.9% and 20.5% for the three and nine months ended September 30, 2018, respectively, and 9.1% and 87.0% for the three and nine months ended September 30, 2017, ~~respectively, and 38.3% and 38.1% for the three and nine months ended September 30, 2016,~~ 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. The lower effective tax rate for the nine months ended September 30, 2018 was primarily due to the lower enacted tax rate under the Tax Act.

Our Liquidity, capital resources and capital commitments

Overview

Our primary sources of capital resources and Liquidity (defined as cash and restricted cash plus the unused borrowing base under the DIP Credit Agreement) have historically consisted of internally generated cash flows from operations, ~~borrowing capacity~~borrowings under ~~the EXCO Resources Credit Agreement,~~certain credit agreements, issuances of debt securities, dispositions of non-strategic assets, joint ventures and the capital markets when conditions are favorable. Our ability to issue additional indebtedness, dispose assets, enter into joint ventures or access the capital markets may be substantially limited or nonexistent during the Chapter 11 Cases and will require

court approval in most instances. Accordingly, our Liquidity will depend mainly on cash generated from operating activities and available funds under the DIP Credit Agreement. Factors that could impact our Liquidity, capital resources and capital commitments include the following:

~~potential acquisitions and/~~significant costs associated with the bankruptcy process, including our ability to limit these costs by obtaining confirmation of a successful plan of reorganization in a timely manner;

decisions from the Court related to requirements to pay interest on certain debt instruments during the bankruptcy process;

decisions from the Court related to the rejection of certain executory contracts;

our ability to maintain compliance with debt covenants under the DIP Credit Agreement;

reductions to our borrowing base under the DIP Credit Agreement, which may begin on January 1, 2019 or ~~dispositions~~later if the maturity of ~~oil~~the DIP Credit Agreement is extended;

our ability to fund, finance or repay indebtedness, including our ability to restructure our indebtedness during the Chapter 11 Cases;

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

requirements to provide certain vendors and ~~natural gas properties~~other parties with letters of credit or ~~other assets;~~

~~the outcome~~cash deposits as a result of our ~~review~~credit quality, which reduce the amount of ~~strategic alternatives, which may include, but not be limited~~available borrowings under the DIP Credit Agreement;

our ability to ~~seeking a comprehensive out-of-court~~obtain exit financing on favorable terms in order to consummate the Plan or an alternative restructuring ~~or reorganization under Chapter 11 of the U.S. Bankruptcy Code;~~transaction;

the level of planned drilling activities;

the results of our ongoing drilling programs;

~~our ability to fund, finance~~ potential acquisitions and/or ~~repay indebtedness, including the EXCO Resources Credit Agreement~~dispositions of oil and ~~2018 Notes that mature in July and September 2018, respectively;~~natural gas properties or other assets;

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, specifically related to ~~recent~~ pricing pressures from key vendors utilized in our drilling, completion and operating activities;

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

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

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

~~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 decisions to pay interest on the 1.5 Lien Notes and 1.75 Lien Term Loans in cash, common shares or additional indebtedness;~~

~~reductions to our borrowing base;~~

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

~~additional debt restructuring activities, which may include seeking relief under the U.S. Bankruptcy Code;~~

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

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

Recent events affecting Liquidity

On ~~March~~January 15, ~~2017,~~2018, the Company and the Filing Subsidiaries filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. On January 22, 2018, we closed ~~a series~~the DIP Credit Agreement, which includes an initial borrowing base of transactions including the issuance of $300.0 million in aggregate principal amount of 1.5 Lien Notes and the exchange of $682.8 million in aggregate principal amount of the Second Lien Term Loans for 1.75 Lien Term Loans. The transaction fees paid to the lenders included a combination of cash and warrants to purchase our common shares. The terms of the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans allow for interest payments in cash, common shares or additional indebtedness, subject to certain restrictions and limitations. The proceeds$250.0 million. Proceeds from the ~~issuance of the 1.5 Lien Notes~~DIP Credit Agreement were ~~primarily utilized~~used to repay outstanding indebtedness under the EXCO Resources Credit Agreement. In connection with these transactions, the EXCO Resources Credit Agreement was amended to reduce the borrowing base to $150.0 million, permit the issuance of the 1.5 Lien Notes and the exchanges of Second Lien Term Loans, and modify certain financial covenants.

On June 20, 2017, we paid interest on the 1.75 Lien Term Loans in common shares, which resulted in the issuance of 2,745,754 common shares ("PIK Shares") in lieu of an approximate $23.0 million cash interest payment under the 1.75 Lien Term Loans. On September 20, 2017, we paid $17.0 million and $26.2 million of interest on the 1.5 Lien Notes and 1.75 Lien Term Loans, respectively, through the issuance of additional 1.5 Lien Notes and 1.75 Lien Term Loans. As discussed below in the "Liquidity concerns and going concern assessment" section, we are currently restricted from paying interest in common shares and our ability to pay interest in additional indebtedness is limited.

~~During the third quarter of 2017, we borrowed substantially~~ all ~~of our remaining unused commitments~~obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. We have limited our 2018 forecasted capital expenditures to $152.0 million in order to preserve our Liquidity during the pendency of the bankruptcy process. Our Liquidity was $155.6 million as of September 30, ~~2017,~~2018. We believe our cash flow from operations, borrowing capacity under the DIP Credit Agreement and cash on hand will provide sufficient Liquidity during the bankruptcy process. We expect to incur significant costs associated with the bankruptcy process, including legal, financial and restructuring advisors to the Company and certain of our creditors. Additionally, the DIP Credit Agreement matures on January 22, 2019 unless we ~~had $126.4 million~~are able to extend the maturity by obtaining a waiver or consent from the DIP Lenders. Therefore, our ability to obtain confirmation of ~~outstanding~~a successful plan of reorganization in a timely manner is critical to ensuring our Liquidity is sufficient during the bankruptcy process.

The Plan provides for a reorganization of the Debtors as a going concern with a significant reduction in indebtedness and ~~$23.6 million of outstanding letters of credit~~improved capital structure. The Debtors shall fund distributions under the ~~EXCO Resources Credit Agreement. As~~Plan with: (i) cash on hand; (ii) a ~~result, we had $105.8 million~~new revolving credit facility (“Exit Facility”); (iii) a new second lien debt instrument; (iv) the equity in the reorganized Company; and (v) the proceeds from carriers of ~~Liquidity~~directors’ and no availability remaining under the EXCO Resources Credit Agreement, including letters of credit, as of September 30, 2017. The borrowing base under the EXCO Resources Credit Agreement remains subject to semi-annual review

~~and redetermination by the lenders pursuant~~officers’ liability insurance coverage related to the ~~terms~~Debtors. Our ability to consummate the Plan is dependent upon our ability to issue the Exit Facility and a new second lien debt instrument. We are currently engaged in discussions with financial institutions regarding the potential issuance of the ~~EXCO Resources Credit Agreement. The redetermination of~~Exit Facility and a new second lien debt instrument. There can be no assurance the ~~borrowing base scheduled for November 2017 is currently in process. The lenders party~~exit financing required to consummate the ~~EXCO Resources Credit Agreement have considerable discretion in setting our borrowing base, and we are unable to predict the outcome of the redetermination.~~

Our Liquidity will continue to be negatively impacted by significant interest and principal payments related to our indebtedness, and gathering, transportation and certain other commercial contracts. As a result of our credit rating and financial condition, we have experienced and may continue to experience increased demands from vendors for changes to payment terms and other financial assurances, including letters of credit, all of which negatively impact our trade credit and Liquidity. In addition, our future LiquidityPlan will be impacted from the increase in professional and legal fees resulting from our restructuring activities. We continue to evaluate additional transactions to restructure our existing indebtedness and address near-term liquidity needs, which may include in-courtavailable or, ~~out-of-court restructuring.~~if available, offered on acceptable terms. See ~~below for~~ further discussion of the key proposed restructuring elements contemplated in the Plan and the confirmation process in “Note 1. Organization and basis of presentation” in the Notes to our ~~Liquidity~~Condensed Consolidated Financial Statements. The primary sources of liquidity for the reorganized Company are expected to consist of internally generated cash flows from operations and available borrowings under the Exit Facility. The capital structure proposed in the Plan is expected to provide us with sufficient liquidity and financial flexibility in order to execute our ~~ability to continue as a going concern.~~business plan.

~~Overview of debt, Liquidity, cash interest and maturities~~

The following table presents our Liquidity and outstanding principal balances of our debt as of September 30, ~~2017:~~2018:


(in thousands)	September 30, 2017		September 30, 2018
EXCO Resources Credit Agreement	$	126,401
DIP Credit Agreement			$	156,406
1.5 Lien Notes	316,958		316,958
1.75 Lien Term Loans ~~(1)~~	708,926		708,926
Exchange Term Loan (1)	17,246
Second Lien Term Loans			17,246
2018 Notes	131,576		131,576
2022 Notes	70,169		70,169
Total debt ~~(2)~~	$	1,371,276	$	1,401,281
Net debt	$	1,265,438	$	1,327,290
Borrowing base	$	150,000	$	250,000
Unused borrowing base ~~(3)~~(1)	$	—	$	81,600
Cash ~~(4)~~(2)	$	105,838	$	73,991
Unused borrowing base plus cash	$	105,838	$	155,591


(1)	Amounts presented are the outstanding principal balances and exclude $154.2 million and $6.3 million of deferred reductions to carrying value on the 1.75 Lien Term Loans and the Exchange Term Loan, respectively. See "Note 8. Debt" in the Notes to our Condensed Consolidated Financial Statements for additional information.


~~(2)~~	~~Excludes unamortized discounts and deferred financing costs.~~


~~(3)~~	Net of ~~$23.6~~$12.0 million in letters of credit at September 30, ~~2017.~~2018.


~~(4)~~(2)	Includes restricted cash of ~~$23.4~~$7.0 million at September 30, ~~2017.~~2018.

~~Set forth below is~~As of the Petition Date, we had approximately $1.4 billion in principal amount of indebtedness. The filing of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the following debt instruments: (i) EXCO Resources Credit Agreement; (ii) 1.5 Lien Notes; (iii) 1.75 Lien Term Loans; (iv) 2018 Notes; and (v) 2022 Notes. These debt instruments provide that as a ~~summary~~result of the commencement of the Chapter 11 Cases, the principal and interest due thereunder shall be immediately due and payable. In addition, we were in default under the Second Lien Term Loans as a result of our ~~outstanding indebtedness~~failure to make interest payments. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of ~~September 30, 2017, related maturity dates~~the commencement of the Chapter 11 Cases, and ~~a summary~~the creditors’ rights of ~~cash~~enforcement with respect to the debt instruments are subject to the applicable provisions of the Bankruptcy Code. Proceeds from the DIP Credit Agreement were used to repay all obligations under the EXCO Resources Credit Agreement and the EXCO Resources Credit Agreement was terminated. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest ~~rates:~~on the DIP Credit Agreement and the 1.5 Lien Notes.

(in thousands) Principal amount outstanding Maturity date Frequency of payment Annual cash interest rate
EXCO Resources Credit Agreement $ 126,401
July 31, 2018 Monthly
⁽¹⁾
1.5 Lien Notes 316,958
March 20, 2022 Semi-annually 8.0%
1.75 Lien Term Loans 708,926
October 26, 2020 Quarterly 12.5%
Exchange Term Loan 17,246
October 26, 2020 Quarterly 12.5%
2018 Notes 131,576
September 15, 2018 �� Semi-annually 7.5%
2022 Notes 70,169
April 15, 2022 Semi-annually 8.5%
Total debt $ 1,371,276

The DIP Credit Agreement contains certain financial covenants, including, but not limited to:


~~(1)~~	The interest rate grid on the revolving credit facility of the EXCO Resources Credit Agreement, as amended on September 29, 2017, ranges from LIBOR plus 250 bps to 350 bps (or ABR plus 150 bps to 250 bps), depending on the percentages of drawn balances to the borrowing base.

our cash (as defined in the DIP Credit ~~agreements~~Agreement) plus unused commitments under the DIP Credit Agreement cannot be less than $20.0 million (“Minimum Liquidity Test”); and ~~long-term debt~~

aggregate disbursements cannot exceed 120% of the aggregate disbursements (excluding professional fees incurred in the Chapter 11 Cases) set forth in the 13-week forecasts provided to the administrative agent of the DIP Credit Agreement. The testing period is based on the immediately preceding four-week period and is measured every two weeks. The 13-week forecast is provided to the administrative agent on a monthly basis and shall be consistent in all material respects with the applicable period covered by the 2018 budget that was previously delivered to the administrative agent of the DIP Credit Agreement.

As of September 30, ~~2017, our consolidated debt consisted~~2018, we were in compliance with all of the ~~EXCO Resources~~covenants under the DIP Credit Agreement. The DIP Credit Agreement ~~1.5 Lien Notes, 1.75 Lien Term Loans, Exchange Term Loan,~~contains events of default, including: (i) conversion of the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code and (ii) appointment of a trustee, examiner or receiver in the Chapter 11 Cases. The DIP Credit Agreement will mature on the earliest of (a) 12 months from the initial borrowings on January 22, 2018, ~~Notes~~(b) the effective date of a plan of reorganization in the Chapter 11 Cases and ~~2022 Notes.~~(c) the date of termination of all revolving commitments and/or the acceleration of the obligations under the DIP Facilities following an event of default. The DIP Credit Agreement provided us with an option to extend the maturity of the DIP Facilities to the date that is 18 months from the initial borrowing date if certain conditions are met. These conditions included a requirement to file a plan of reorganization with the Court no later than July 1, 2018. We did not file a plan of reorganization with the Court prior to July 1, 2018; therefore, an extension of the DIP Facilities beyond the original maturity date would require a waiver or consent from the DIP Lenders. See ~~"Note~~further discussion of the DIP Credit Agreement in “Note 8. ~~Debt"~~Debt” in the Notes to our Condensed Consolidated Financial ~~Statements for a more detailed description of each agreement.~~

~~As of September 30, 2017, we were in compliance with the following financial covenants (each as defined in the EXCO Resources Credit Agreement):~~

our cash (as defined in the EXCO Resources Credit Agreement) plus unused commitments under the EXCO Resources Credit Agreement of $102.9 million exceeded the required minimum of $70.0 million as of the end of a fiscal quarter ("Minimum Liquidity Test");

our ratio of consolidated EBITDAX to consolidated interest expense (“Interest Coverage Ratio”) of 2.2 to 1.0 exceeded the minimum of 1.75 to 1.0 for the fiscal quarter ending September 30, 2017. The Interest Coverage Ratio cannot be less than 2.0 to 1.0 for all future fiscal quarters. The consolidated EBITDAX and consolidated interest expense utilized in this ratio are based on the most recent fiscal quarter ended multiplied by 4.0 as of September 30, 2017, the most recent two fiscal quarters ended multiplied by 2.0 as of December 31, 2017, the most recent three fiscal quarters ended multiplied by 4/3 as of March 31, 2018, and the trailing twelve month period for fiscal quarters ending thereafter. The definition of consolidated interest expense includes cash interest payments that are accounted for as reductions in the carrying amount of indebtedness in accordance with FASB ASC 470-60. The consolidated interest expense utilized in the Interest Coverage Ratio is limited to payments in cash, and excludes PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans.

As of September 30, 2017, our ratio of aggregate revolving credit exposure to consolidated EBITDAX ("Aggregate Revolving Credit Exposure Ratio") of 1.9 to 1.0 exceeded the maximum of 1.2 to 1.0. In anticipation of the potential default, on September 29, 2017, we obtained a limited one-time waiver from the lenders under the EXCO Resources Credit agreement waiving an event of default as a result of a failure to comply with the Aggregate Revolving Credit Exposure Ratio as of September 30, 2017.

~~Liquidity concerns and going concern assessment~~

Our Liquidity is currently significantly constrained. As of September 30, 2017, our Liquidity was $105.8 million and the principal amount of outstanding indebtedness was $1.4 billion. During the nine months ended September 30, 2017, our cash flows used in investing activities exceeded our cash flows from operating activities by $86.3 million. We expect cash flows used in investing activities to continue to exceed cash flows from operating activities during the remainder of 2017 and future periods. Our Liquidity may not be sufficient to fund this cash flow deficit and conduct our business operations unless we are able to restructure our current obligations under our existing outstanding debt and address near-term liquidity needs. The significant risks to our Liquidity and ability to continue as a going concern are described below.

~~No further availability of credit under EXCO Resources Credit Agreement~~

During the third quarter of 2017, we borrowed substantially all of our remaining unused commitments under the EXCO Resources Credit Agreement, and, as of September 30, 2017, we had $126.4 million of outstanding indebtedness and $23.6 million of outstanding letters of credit under the EXCO Resources Credit Agreement as of September 30, 2017. As a result, we had no availability remaining under the EXCO Resources Credit Agreement, including letters of credit, as of September 30, 2017. 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. The redetermination of the borrowing base scheduled for November 2017 is currently in process. 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 the redetermination.

~~Compliance with debt covenants~~

The EXCO Resources Credit Agreement requires that our Aggregate Revolving Credit Exposure Ratio cannot exceed 1.2 to 1.0 as of the end of any fiscal quarter. As of September 30, 2017, our Aggregate Revolving Credit Exposure Ratio exceeded the allowed maximum of 1.2 to 1.0. In anticipation of the potential default, on September 29, 2017, we obtained a limited one-Statements.

time waiver from the lenders under the EXCO Resources Credit Agreement waiving an event of default as a result of a failure to comply with the Aggregate Revolving Credit Exposure Ratio as of September 30, 2017. We believe it is probable that we will not be in compliance with the Aggregate Revolving Credit Exposure Ratio as of December 31, 2017.

The EXCO Resources Credit Agreement also requires that our Minimum Liquidity Test cannot be less than (i) $50.0 million as of the end of a fiscal month and (ii) $70.0 million as of the end of a fiscal quarter. It is probable that we will not be in compliance with the Minimum Liquidity Test for the twelve-month period following the date of these unaudited Condensed Consolidated Financial Statements and may not be able to comply with this covenant as early as of the end of the fourth quarter of 2017. In addition, the EXCO Resources Credit Agreement requires that our Interest Coverage Ratio exceeds a minimum of 1.75 to 1.0 for the fiscal quarter ending September 30, 2017 and 2.0 to 1.0 for fiscal quarters thereafter. The definition of consolidated interest expense utilized in the Interest Coverage Ratio excludes PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans. The consolidated EBITDAX and consolidated interest expense utilized in this calculation are annualized beginning with the fiscal quarter ending September 30, 2017. Therefore, we believe that our ability to make interest payments in common shares is essential to maintain compliance with the Interest Coverage Ratio and as described below, we are currently limited from making future PIK Payments in our common shares.

If we deliver to our lenders an audit report prepared by our auditors with respect to the financial statements for the fiscal year ended December 31, 2017 that includes an explanatory paragraph expressing uncertainty as to our ability to continue as a going concern, then it will be an event of default under each of the EXCO Resources Credit Agreement, 1.5 Lien Notes, and 1.75 Lien Term Loans. These defaults would also result in a default under the indenture governing our 2018 Notes and 2022 Notes. We may not be able to eliminate the substantial doubt concerning our ability to continue as a going concern or obtain waivers with respect to this obligation from our lenders. If the substantial doubt about our ability to continue as a going concern remains at the date we deliver our financial statements for the fiscal year ended December 31, 2017, we would experience an event of default under such agreements.

~~Limitations on ability to pay interest on 1.5 Lien Notes and 1.75 Lien Term Loans~~

The principal purpose of offering the 1.5 Lien Notes and Second Lien Term Loan Exchange was to alleviate the substantial cash interest payment burden and improve our Liquidity. Our initial expectation was to make PIK Payments in common shares on the 1.5 Lien Notes and the 1.75 Lien Term Loans throughout the remainder of 2017 and 2018. However, under our Registration Rights Agreement with the holders of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans ("Registration Rights Agreement"), our ability to make PIK Payments in common shares is subject to a resale registration statement related to the common shares issued as PIK Payments and all of the shares underlying the warrants issued in connection with the 1.5 Lien Notes and 1.75 Lien Term Loans being declared effective by the SEC by October 11, 2017 ("Resale Registration Statement"). We did not anticipate the Resale Registration Statement would be declared effective as of October 11, 2017, and, as such, we provided a notice of a delay of effectiveness for the Resale Registration Statement to the holders of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans, as permitted under the Registration Rights Agreement, extending the requirement for the Resale Registration Statement to be declared effective to no later than December 8, 2017. As of the date of the filing of this Quarterly Report on Form 10-Q, the Resale Registration Statement has not been declared effective and there is no assurance we will be able to satisfy this condition.

Even if the Resale Registration Statement is declared effective allowing us to make PIK Payments in common shares, the terms of the indenture governing the 1.5 Lien Notes and the credit agreement governing the 1.75 Lien Term Loans prohibit the issuance of common shares as PIK Payments if it would result in a beneficial owner, directly or indirectly, owning more than 50% of our outstanding common shares. Our common share price has been, and continues to be, volatile and has significantly decreased during 2017. If our common share price remains at the current levels or continues to decrease, we will have to issue a greater number of common shares to make PIK Payments on the 1.5 Lien Notes and 1.75 Lien Term Loans. This could prevent us from paying interest in common shares due to the 50% ownership limitation. In addition, we may elect not to make PIK Payments because such issuances would contribute to an ownership change under Section 382 of the Internal Revenue Code that could limit our ability to use our NOLs to reduce future taxable income. As of September 30, 2017, we had estimated NOLs of $2.4 billion.

~~Near-term debt maturities~~

~~Other factors~~

Our Liquidity and compliance with debt covenants may be impacted by the outcome of certain litigation. As described in "Item 3. Legal Proceedings" in our 2016 Form 10-K, we are currently in litigation with Enterprise Products Operating LLC ("Enterprise") and Acadian Gas Pipeline System ("Acadian") in which Enterprise and Acadian filed a suit claiming that we improperly terminated the sales and transportation contracts with them. If we are unable to satisfactorily resolve our litigation with Enterprise and Acadian and we are required to pay a judgment, any such payment could adversely affect our ability to pay the principal and interest on our outstanding debt. Furthermore, we expect to have a shortfall under a minimum volume commitment for gathering services in the East Texas and North Louisiana regions for the twelve-month period ending November 30, 2017. As of September 30, 2017, we accrued $19.5 million in "Revenues and royalties payable" in our Condensed Consolidated Balance Sheet related to this shortfall and the payment is due within 90 days of the end of the twelve-month period ending November 30, 2017. The payment of this shortfall is expected to have a significant impact on our Liquidity.

~~Management's plans~~

On September 7, 2017, we announced that our Board of Directors has delegated authority to the independent directors of the Audit Committee to explore strategic alternatives to strengthen our balance sheet and maximize the value of the Company, which may include, but is not limited to, seeking a comprehensive out-of-court restructuring or reorganization under Chapter 11 of the U.S. Bankruptcy Code. Our plans may include obtaining additional financing or relief from debt holders to support operations throughout the restructuring process, delevering our capital structure, and reducing the financial burden of certain gathering, transportation and other commercial contracts. At the direction of the Audit Committee, we have retained PJT Partners LP as financial advisors and Alvarez & Marsal North America, LLC as restructuring advisors. We continue to retain

Kirkland & Ellis LLP as our legal advisor to assist the Audit Committee and management team with the restructuring process. We are actively engaged in negotiations with our stakeholders to evaluate the feasibility of a consensual in-court or out-of-court restructuring.

~~Assessment of ability to continue as a going concern~~

Capital expenditures

Our 2018 forecasted ~~2017~~ capital expenditures of ~~$167.0~~$152.0 million are focused primarily on the ~~exploitation and~~ development of the Haynesville and ~~Bossier shales~~Eagle Ford shales. During 2018, we revised our original capital budget for 2018 to reflect the impact of non-consent elections by partners in certain of our operated wells, drill additional wells in South Texas with attractive rates of return, and complete additional wells that were previously drilled during prior year in North Louisiana based on a settlement agreement with a joint venture partner. The development of the Haynesville shale in North Louisiana includes drilling 1 gross (0.7 net) operated well and completing 11 gross (6.7 net) operated wells. The completion activities in North Louisiana primarily include wells drilled in prior year. Based on the settlement agreement reached with a joint venture partner in the fourth quarter of 2018, we agreed to commence the completion of 4 gross (1.2 net) wells that were previously drilled in North Louisiana no later than November 15, 2018, and subsequently commence the completion of 3 gross (2.2 net) additional wells that were previously drilled in North Louisiana. ~~The forecasted 2017 capital expenditures represent an increase from our capital budget primarily due~~These wells are not expected to be completed and turn-to-sales until the ~~acquisition~~first quarter of ~~additional interests in wells included in~~2019.

Our development program for the ~~development program. We plan to spend approximately $119.0 million to drill 36~~Eagle Ford shale includes drilling 14 gross ~~(20.4~~(11.3 net) operated wells and ~~complete 14~~completing 16 gross ~~(10.1~~(12.9 net) operated wells ~~during 2017. The operated wells included as part~~that will preserve the value of ~~our 2017 plans feature a modified well design that builds on the success~~certain acreage with leasehold obligations and provide attractive rates of the results from our development program in the North Louisiana and East Texas regions, including the use of more proppant and extended laterals. The completion methods include extended laterals up to 10,000 feet and an average of 3,500 lbs of proppant per lateral foot. We continue to focus on operational initiatives to enhance our well designs, optimize our base production and maximize recoveries from our properties. In addition, our capital budget includes approximately $30.0 million ofreturn. Our drilling and completion activities ~~operated by others for wells~~include $21.0 million to participate in the ~~Haynesville~~development of non-operated wells. In addition, we plan to spend a limited amount of capital on maintenance and ~~Bossier shales in North Louisiana and East Texas. Furthermore, we continue to evaluate and pursue accretive leasing and acquisition opportunities to increase our drilling inventory.~~leasehold costs.

For the nine months ended September 30, ~~2017,~~2018, our capital expenditures totaled ~~$107.3~~$124.4 million, of which ~~$91.1~~$118.1 million was primarily related to development capital expenditures. Our development activities in North Louisiana included drilling 1 gross (0.7 net) operated well and completing 11 gross (6.7 net) operated wells in the Haynesville shale. The forecasted development activities in North Louisiana for the remainder of 2018 will primarily consist of the ~~Haynesville shale and the appraisal~~completion of ~~the Bossier shale~~wells that were previously drilled in ~~North Louisiana.~~prior year. Our development ~~program during the nine months ended September 30, 2017~~activities in South Texas included drilling 2614 gross ~~(16.1~~(11.3 net) operated wells and ~~turning-to-sales 4~~completing 9 gross ~~(3.5~~(8.6 net) ~~wells.~~operated wells in the Eagle Ford shale. We expect to complete 7 gross (4.3 net) operated wells in South Texas in the fourth quarter of 2018. In addition, we turned-to-sales 1 gross (0.9 net) operated Marcellus shale well in Northeast Pennsylvania that was previously awaiting the connection of a pipeline.

The following table presents our capital expenditures for the nine months ended September 30, ~~2017~~2018 and our forecasted capital expenditures for the remainder of ~~2017:~~2018:

Nine Months Ended October - December Forecast Full Year Forecast
(in thousands) September 30, 2017 2017 2017
Capital expenditures:
Development capital expenditures $ 91,133
$ 57,867
$ 149,000
Other (1) 16,176
1,824
18,000
Total $ 107,309
$ 59,691
$ 167,000

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



	Nine Months Ended September 30, 2018		October - December 2018 Forecast		2018 Forecasted Capital Expenditures
(in thousands)	Nine Months Ended September 30, 2018		October - December 2018 Forecast		2018 Forecasted Capital Expenditures
Capital expenditures:
Lease purchases and seismic	$	476	$	1,524	$	2,000
Development capital expenditures	118,093		21,907		140,000
Field operations, gathering and water pipelines	918		3,082		4,000
Corporate and other	4,875		1,125		6,000
Total	$	124,362	$	27,638	$	152,000

Historical sources and uses of funds

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


	Nine Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2017			2016			2018			2017
Net cash provided by (used in) operating activities	$	51,107		$	(3,740	)
Net cash provided by operating activities							$	109,536		$	51,107
Net cash used in investing activities	(137,376		)	(56,150		)	(114,356		)	(125,147		)
Net cash provided by financing activities	159,660			51,177			23,943			159,660
Net increase (decrease) in cash	$	73,391		$	(8,713	)
Net increase in cash							$	19,123		$	85,620

Operating activities

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

been impacted by fluctuations in oil and natural gas prices and our production volumes.

For the nine months ended September 30, ~~2017,~~2018, our net cash provided by operating activities was ~~$51.1~~$109.5 million as compared to net cash ~~used in~~provided by operating activities of ~~$3.7~~$51.1 million for the nine months ended September 30, ~~2016.~~2017. The increase in cash provided by operating activities was primarily due to ~~higher oil~~increases in revenues, reductions in operating expenses and ~~natural gas prices, lower cash interest payments and more~~ favorable changes in working capital. As a result of the bankruptcy proceedings, we experienced favorable changes in working capital ~~conversions, partially offset by lower production~~during the nine months ended September 30, 2018 due to the deferral of payments that are subject to the approval of the Court, our creditors or confirmation of a plan of reorganization. See “Note 1. Organization and ~~lower cash receipts on derivative contracts.~~basis of presentation” in the Notes to our Condensed Consolidated Financial Statements for further discussion of the impact of the Chapter 11 Cases.

Investing activities

Our investing activities consist primarily of drilling and development expenditures, acquisitions and divestitures. ~~Future acquisitions are dependent~~For the nine months ended September 30, 2018, our net cash used in investing activities was $114.4 million, which primarily consisted of development activities focused on ~~oil~~the North Louisiana and ~~natural gas prices, availability~~South Texas regions of ~~attractive acreage~~$130.1 million. This is partially offset by $14.8 million of cash held by OPCO and ~~other oil and natural gas properties, acceptable rates~~Appalachia Midstream that was acquired as a result of ~~return, availability of borrowing capacity under~~ the ~~EXCO Resources Credit Agreement and availability of other sources of capital.~~

Appalachia JV Settlement. For the nine months ended September 30, 2017, our net cash used in investing activities was ~~$137.4~~$125.1 million, ~~that~~which primarily consisted of ~~drilling and completion~~development activities ~~and oil and natural gas property acquisitions~~ in the North Louisiana region.

Financing activities

For the nine months ended September 30, ~~2016,~~2018, our net cash ~~used in investing~~provided by financing activities was ~~$56.2~~$23.9 million. Proceeds from the DIP Credit Agreement were used to repay all obligations outstanding under the EXCO Resources Credit Agreement and will provide additional liquidity to fund our operations during the Chapter 11 process. In addition, we spent $6.1 million ~~primarily due~~of financing costs related to issuance of the DIP Facilities. See “Note 8. Debt” in the Notes to our ~~completion activities in~~Condensed Consolidated Financial Statements for further discussion of the East Texas region and drilling activities in the North Louisiana region. This was partially offset by $11.2 million of proceeds received from a sale of certain non-core undeveloped acreage in South Texas and our interests in four producing wells.DIP Facilities.

~~Financing activities~~

For the nine months ended September 30, 2017, our net cash provided by financing activities was $159.7 ~~million. We received~~million primarily due to $295.5 million of net proceeds from the 1.5 Lien Notes, which we used to repay borrowings under the EXCO Resources Credit Agreement. We subsequently had net borrowings of $126.4 million under the EXCO Resources Credit Agreement, which exhausted our remaining unused commitments under the EXCO Resources Credit Agreement. In addition, we used cash to pay $22.1 million of costs primarily related to debt restructuring activities during the first quarter of 2017, and we made payments of $11.6 million on a portion of the ~~Exchange~~Second Lien Term ~~Loan,~~Loans, which reduced its carrying value.

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

Commodity derivative financial instruments

Our production is generally sold at prevailing market prices. ~~However,~~Historically, we ~~periodically enter~~have entered 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.

During the Chapter 11 Cases, our ability to enter into commodity derivative contracts covering estimated future production is limited under the DIP Credit Agreement. We are only permitted to enter into commodity derivative contracts with lenders under the DIP Credit Agreement. As a result, we may not be able to enter into commodity derivative contracts covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivative contracts in the future, we could be more affected by changes in commodity prices. Our inability to hedge the risk of low commodity ~~derivatives are comprised~~prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations. Our exposure to commodity price fluctuations will increase in 2018 due to lower oil and natural gas ~~swap and collar contracts. As of September 30, 2017, we had commodity~~volumes covered by derivative ~~financial instruments in place for the volumes and prices shown below:~~

NYMEX gas volume - Bbtu Weighted average contract price per Mmbtu NYMEX oil volume - Mbbl Weighted average contract price per Bbl
Swaps:
Remainder of 2017 9,200
$ 3.05
46
$ 50.00
2018 3,650
3.15
—
—
Collars:
Remainder of 2017 2,760
—

Sold call 3.28
—
Purchased put 2.87
—

~~We had derivative financial instruments that covered approximately 56% and 59% of production volumes during the three and nine months ended September 30, 2017, respectively.~~contracts compared to historical levels.

See further details on our derivative financial instruments in ~~"Note~~“Note 7. Derivative financial ~~instruments"~~instruments” and ~~"Note~~“Note 9. Fair value ~~measurements"~~measurements” in the Notes to our Condensed Consolidated Financial Statements.

Off-balance sheet arrangements

As of September 30, ~~2017~~,2018, we had no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments

~~There have been no material changes outside the ordinary course~~

As of ~~business to~~December 31, 2017, our contractual obligations and commercial commitments ~~since~~primarily consisted of debt instruments; sales, marketing, gathering and transportation agreements; and leases of office space and certain equipment. The filing of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the following debt instruments: (i) EXCO Resources Credit Agreement; (ii) 1.5 Lien Notes; (iii) 1.75 Lien Term Loans; (iv) 2018 Notes; and (v) 2022 Notes. In addition, we were in default under the Second Lien Term Loans as a result of our failure to make interest payments. Any efforts to enforce such payment obligations under the debt instruments are automatically stayed as a result of the commencement of the Chapter 11 Cases, and the creditors’ rights of enforcement in respect of the debt instruments are subject to the applicable provisions of the Bankruptcy Code. As of the Petition Date, we adjusted the carrying value of our indebtedness to the estimated amount that will be allowed as claims in the Chapter 11 Cases. On January 22, 2018, proceeds from the DIP Credit Agreement were used to repay all obligations outstanding under the EXCO Resources Credit Agreement. On February 22, 2018, the Court approved our ability to make adequate protection payments for interest on the DIP Credit Agreement and the 1.5 Lien Notes. We accrued interest on the 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes through Petition Date, with no interest accrued subsequent to the Petition Date. The 1.75 Lien Term Loans, Second Lien Term Loans, 2018 Notes and 2022 Notes have been reclassified as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet as of September 30, 2018.

During March 2018, the Court approved the rejection of certain executory contracts related to the sale, marketing and transportation of natural gas in the North Louisiana region. The rejection of these executory contracts was treated as a breach as of the Petition Date and relieved us from performing future obligations under such contract but is expected to result in a general unsecured claim against certain of the Debtors for damages caused by such rejection. On August 9, 2018, the Court approved the rejection of the office lease for our corporate headquarters in Dallas, Texas. We subsequently entered into a new lease for a reduced amount of square footage in the same office building with a term through December 31, ~~2016.~~2022.

Our estimate of allowable claims related to the executory contracts approved for rejection by the Court was recorded as “Liabilities subject to compromise” on our Condensed Consolidated Balance Sheet as of September 30, 2018. See “Item 1. Legal Proceedings” for further discussion regarding the adversary proceeding related to an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure through November 30, 2018.

See further discussion of the impact of the Chapter 11 Cases on our indebtedness and the rejection of executory contracts in “Note 1. Organization and basis of presentation” in the Notes to our Condensed Consolidated Financial Statements.

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, and interest rates charged on borrowings and earned on cash equivalent ~~investments, and adverse changes in the market value of marketable securities.~~investments. 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 derivative financial instruments ~~were~~have historically been entered into for hedging and investment purposes, not for trading purposes.

Commodity price risk

Our ~~objective~~most significant market risk exposure is in ~~entering~~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. We have historically entered into commodity 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~~

During the effect of our commodity derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our commodity 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 restrictChapter 11 Cases, our ability to enter into ~~certain types of~~ commodity derivative ~~financial instruments and limit~~contracts covering estimated future production is limited under the ~~maturity of the~~DIP Credit Agreement. We are only permitted to enter into commodity derivative contracts with ~~counterparties.~~

~~Our most significant market risk exposure is in~~lenders under the ~~pricing applicable~~DIP Credit Agreement. As a result, we may not be able 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~~enter into commodity derivative ~~financial instruments could have the effect of reducing~~contracts covering our ~~revenues and the value of our securities. For the nine months ended September 30, 2017, a $1.00 increase~~production 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 $29.9 million for our oil and natural gas swap contracts. The ultimate settlement amount of our outstandingfuture periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivative ~~financial instrument~~ contracts ~~is dependent on future commodity prices. We may incur significant unrealized losses~~ in the future, ~~from~~we could be more affected by changes in commodity prices. Our inability to hedge the risk of low

commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our ~~use~~business, financial condition and results of ~~commodity derivative financial instruments to the extent market prices increase and our commodity derivatives contracts remain in place.~~operations. Our exposure to commodity price fluctuations will increase in 2018 due to lower oil and natural gas volumes covered by derivative contracts compared to historical levels. For the three and nine months ended September 30, 2018, a $1.00 decrease in the average commodity price per Mcfe would have resulted in a decrease in oil and natural gas revenues, excluding the impact of commodity derivative financial instruments, of approximately $27.0 million and $82.0 million, respectively.

Interest rate risk

Our exposure to interest rate changes ~~related~~relates primarily to borrowings under the ~~EXCO Resources~~DIP Credit Agreement. Interest is payable on borrowings under the ~~EXCO Resources~~DIP Credit Agreement based on a floating rate as more fully described in ~~"Note~~“Note 8. ~~Debt"~~Debt” in the Notes to our Condensed Consolidated Financial Statements. At September 30, ~~2017,~~2018, we had ~~$126.4~~$156.4 million in borrowings outstanding under the ~~EXCO Resources~~DIP Credit Agreement. A 1.0% increase in interest rates (100 bps) based on the variable borrowings as of September 30, 2018 would result in an increase in our interest expense of approximately $1.6 million per year. The interest rate we pay on these borrowings is set periodically based upon market rates.

The interest rates per annum on the 2018 Notes, 2022 Notes and Exchange Term Loan are fixed at 7.5%, 8.5% and 12.5%, respectively. The 1.5 Lien Notes bear interest at a cash interest rate of 8% per annum, or, if we elect to make interest payments on the 1.5 Lien Notes, ~~with our common shares or, in certain circumstances, by issuing additional 1.5 Lien Notes, at an interest rate of 11% per annum. The~~ 1.75 Lien Term Loans, ~~bear~~Second Lien Terms Loans, 2018 Notes, and 2022 Notes are fixed and not subject to change based on fluctuations in interest ~~at a cash rate~~rates. Furthermore, fluctuations in interest rates may affect the terms and availability of ~~12.5% per annum, or, if we elect to~~

~~pay interest on the 1.75 Lien Term Loans with our common shares or, in certain circumstances, by issuing additional 1.75 Lien Term Loans, at an interest rate of 15.0% per annum.~~

~~Equity price risk~~

Our exposure to changes in our common share price primarily relate to the 2017 Warrants. We account for the 2017 Warrants as derivative instruments and record the warrants as a non-current liability at fair value, with the increase or decrease in fair value being recognized in earnings. The 2017 Warrantsexit financing that will be ~~measured at fair value on a recurring basis until~~required to consummate the ~~underlying common share warrants are exercised~~contemplated plan of reorganization or the date of expiration. The 2017 Warrants had a fair value of $14.6 million on September 30, 2017. As of September 30, 2017, a 10% increase in the price of our common shares would have increased the fair value of the liability related to the 2017 Warrants by approximately $1.9 million.an alternative restructuring transaction.

Item 4. Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, ~~EXCO's~~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~~EXCO’s disclosure controls and procedures were effective as of September 30, ~~2017~~2018 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~~SEC’s rules and forms and (ii) accumulated and communicated to ~~EXCO's~~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~~EXCO’s internal control over financial reporting that occurred during the quarter ended September 30, ~~2017~~2018 that have materially affected, or are reasonably likely to materially affect, ~~EXCO's~~EXCO’s internal control over financial reporting.

PART II—OTHER INFORMATION


Item 1.	Legal Proceedings

InWe are party to various litigation matters in both the ordinary course of business ~~we are periodically a party to various~~and in connection with the Chapter 11 Cases.

Enterprise and Acadian contract litigation ~~matters.~~

As described in ~~"Item~~“Item 3. Legal ~~Proceedings"~~Proceedings” in our ~~2016~~2017 Form 10-K, we are currently in litigation with Enterprise Products Operating LLC and Acadian Gas Pipeline System (collectively, “Enterprise”) in which Enterprise ~~and Acadian~~ filed a suit claiming that we improperly terminated ~~the~~certain sales and transportation contracts. ~~We have filed a summary judgment motion, which is pending before the court. If we prevail on the summary judgment motion it could be case dispositive. This case is currently set for trial on~~On February ~~5, 2018.~~

On June 6, 2017, we filed a petition, application for temporary restraining order and temporary injunction against Chesapeake Energy Marketing, LLC ("CEML") in Dallas County, Texas, Cause No.DC-17-06672, in the 14th District Court of Dallas County, Texas, for allegedly terminating a long-term sales contract with an expiration of June 30, 2032, between Chesapeake and Raider. We are asserting breach of contract, tortious interference with existing contract, tortious interference with prospective business relations, and declaratory relief that the contract is still in full force and effect. On June 7, 2017, Chesapeake filed to remove the lawsuit to the United States District Court Northern District of Texas. We subsequently joined Chesapeake Energy Corporation ("CEC"). CEC has12, 2018, Enterprise filed a motion to ~~dismiss for lack~~lift the automatic stay of ~~personal jurisdiction,~~the suit under the Bankruptcy Code and continue the suit against us in state court. On March 19, 2018, we filed a motion ~~remains pending. See further discussion in "Note 3. Acquisitions, divestitures and other significant events"~~to extend the automatic stay in the ~~Notes~~Court. On April 19, 2018, the Court entered a stipulation and agreed order pursuant to which, among other matters, Enterprise agreed to, among other things, (i) dismiss with prejudice all claims against Harold Hickey and Steve Estes and (ii) withdraw its motion to lift the automatic stay.

On July 20, 2018, the Debtors filed an objection to all proofs of claim filed by Enterprise (“Enterprise Claims Objection”), and on October 22, 2018, filed a motion seeking summary judgment in favor of the Debtors on account thereof. On October 5, 2018, Enterprise filed a response to the Enterprise Claims Objection and a motion seeking the Court’s abstention therefrom (“Enterprise Abstention Motion”). On October 29, 2018, the Debtors and Bluescape each filed an objection to the Enterprise Abstention Motion.

Shell natural gas sales contract litigation

On March 29, 2018, the Court entered an order granting our motion to dismiss without prejudice the adversary proceeding we had initiated against Shell Energy North America (US) LP (“Shell Energy”), a subsidiary of Shell, regarding Shell Energy’s failure to pay us for sales of natural gas. As described in “Note 12. Subsequent events” to our Condensed Consolidated Financial ~~Statements.~~Statements, we entered into a settlement agreement with a wholly owned subsidiary of Royal Dutch Shell, plc related to revenues that we withheld in response to the aforementioned actions by Shell Energy. The settlement agreement does not prevent us from asserting any claim, cross-claim, defense, or other cause of action against Shell Energy.

Azure minimum volume commitment litigation

On March 1, 2018, the Debtors filed a motion to reject an agreement to deliver an aggregate minimum volume commitment of natural gas production in East Texas and North Louisiana to certain gathering systems owned by Azure Midstream Energy, LLC and TGG Pipeline, Ltd. (collectively, “Azure”) through November 30, 2018. The motion was abated on May, 8, 2018 and on May 16, 2018, EXCO Operating Company, LP and Raider Marketing, LP commenced an adversary proceeding under Adv. Proc. No. 18-03096. The Debtors initiated this adversary proceeding against Azure to establish that the minimum volume commitment agreement is severable from the base gathering agreement between the parties. The Debtors and the contract counterparties each filed various dispositive motions that were heard by the Court on August 9, 2018. The parties have engaged in settlement discussions related to this matter; however, there can be no assurance the parties will be able to reach an agreement. Any settlement reached between the parties would have to be approved by the Court.

Natural gas flaring application

In January 2018, we commenced the flaring of natural gas produced in our South Texas region pursuant to temporary flare permits. In May 2018, we went before the Texas Railroad Commission at a hearing regarding a requested extension of the permits to continue such flaring (the “Flaring Application”) for up to two-years, the maximum time allowable. We expect that a final ruling by the Texas Railroad Commission on the Flaring Application will be issued in the first quarter of 2019.


Item 1A.	Risk Factors

Set forth below are certain material changes to the Risk Factors disclosed in our 2016 Form 10-K, as updated by our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, filed on August 8, 2017:

We have engaged financial and legal advisors to assist us in evaluating potential strategic alternatives related to our capital structure. If we are unable to restructure our debt in private transactions, we may be forced to seek protection from our creditors under the United States Bankruptcy Code, or an involuntary petition for bankruptcy may be filed against us.

We have engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives to restructure our indebtedness. If

we fail to consummate a comprehensive out-of-court restructuring, we may be forced to seek protection from creditors under the U.S. Bankruptcy Code or an involuntary petition for bankruptcy may be filed against us.

We have no borrowing capacity under the EXCO Resources Credit Agreement. Unless we are able to successfully restructure our existing indebtedness, obtain waivers or forbearance from our existing lenders or otherwise raise significant capital, it is unlikely that we will be able to meet our obligations as they become due, and we may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

To emerge successfully from Court protection as a viable entity, we must meet certain statutory requirements with respect to a Chapter 11 plan of reorganization, solicit and obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. Although the Court has approved the Disclosure Statement with respect to the Plan and solicitation of the Plan has commenced, solicitation is not complete and other requirements and statutory conditions necessary for confirmation of the Plan have not yet been satisfied. While the Confirmation Hearing has been scheduled for December 10, 2018, it is possible that hearing could be delayed. It is also possible that the Court will not confirm the Plan.

Creditors may not vote in favor of our Plan, and certain parties in interest may file further objections to the Plan in an effort to persuade the Court that we have not satisfied the confirmation requirements under the Bankruptcy Code. Even if the requisite acceptances of our Plan are received from creditors entitled to vote on the Plan, the Court, which can exercise substantial discretion, may not confirm the Plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class.

Therefore, the outcome of our Chapter 11 process is subject to a high degree of uncertainty and is dependent upon factors outside of our control, including actions of the Court and our creditors. If the Plan is not confirmed by the Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims. We would likely incur significant costs in connection with developing and seeking approval of an alternative plan of reorganization, which might not be supported by any of the current debt holders, various statutory committees or other stakeholders. If an alternative reorganization could not be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity. There can be no assurance as to whether we will successfully reorganize and emerge from the Chapter 11 Cases or, if we do successfully reorganize, as to when we would emerge from the Chapter 11 Cases.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, or market conditions deteriorate, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement will affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to:

changes in the price of oil and natural gas, including our increased exposure since none of our estimated future production is currently covered by commodity derivative contracts;

our ability to obtain adequate liquidity and financing sources, including acceptable terms for the Exit Facility or new second lien debt instrument as contemplated by the Plan;

our ability to maintain the confidence of our vendors, customers and joint interest partners in our viability as a continuing entity and to attract and retain sufficient business with them;

our ability to retain key employees; and

the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets.

Adverse changes in any of these factors could materially affect the successful reorganization of our businesses. Accordingly, the Plan or any alternative Chapter 11 plan of reorganization may not enable us to achieve our goals or continue as a going concern.

~~Our primary sources~~

In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, EBITDA, capital ~~resources~~expenditures, debt service and ~~Liquidity have historically consisted of internally generated~~ cash ~~flows from operations, borrowing capacity under the EXCO Resources Credit Agreement, dispositions of non-strategic assets, joint ventures~~flow. Financial forecasts are necessarily speculative, and capital markets when conditions are favorable. We currently have limited access to additional capital. During the third quarter of 2017, we borrowed substantially all of our remaining unused commitments and had $126.4 million of outstanding indebtedness and $23.6 million of outstanding letters of credit under the EXCO Resources Credit Agreement as of September 30, 2017. As a result, we had no availability remaining under the EXCO Resources Credit Agreement, including letters of credit, as of September 30, 2017.

The accompanying unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. Unless we are able to successfully restructure our existing indebtedness, obtain waivers or forbearance from our existing lenders or otherwise raise significant additional capital, it is ~~unlikely~~likely that we will be able to meet our obligations as they become due, and we may not be able to continue as a going concern. We can provide no assurance that we will be successful in our efforts to restructure our existing indebtedness, obtain further waiversone or ~~forbearance from our existing lenders or otherwise raise significant additional capital.~~

A default under the EXCO Resources Credit Agreement, including for failing to comply with our financial covenants, would result in an acceleration or repayment of all of our outstanding obligations under the EXCO Resources Credit Agreement, the 1.5 Lien Notes, the 1.75 Lien Term Loans, the 2018 Notes and the 2022 Notes.

~~The EXCO Resources Credit Agreement includes covenants that (i) require our Minimum Liquidity Test to be greater than (a) $50.0 million as~~more of the ~~end~~assumptions and estimates that are the basis of a fiscal month and (b) $70.0 million as of the end of a fiscal quarter and (ii) as of the end of a fiscal quarter, our Aggregate Revolving Credit Exposure Ratio for the four preceding consecutive fiscal quarters to be less than 1.2 to 1.0 as of the last day of such fiscal quarter.

As a result of the borrowings under the EXCO Resources Credit Agreement during the third quarter of 2017, we did not believe we would be compliant with the Aggregate Revolving Credit Exposure Ratio as of the fiscal quarter ended September 30, 2017 and therefore entered into the Limited Waiver and Eighth Amendment to the EXCO Resources Credit Agreement, pursuant to which the lenders agreed to waive a potential event of default for our potential failure to comply with the Aggregate Revolving Credit Exposure Ratio as of September 30, 2017. However, no assurance can be given that in the future we will be able to obtain additional waivers for potential failures to comply with covenants under the EXCO Resources Credit Agreement.

A breach of the Minimum Liquidity Test, Aggregate Revolving Credit Exposure Ratio, or other covenants under the EXCO Resources Credit Agreement, if not waived or cured, would result in an event of default under the EXCO Resources Credit Agreement. If an event of default occurs under the EXCO Resources Credit Agreement, the lenders could accelerate the loans outstanding under the EXCO Resources Credit Agreement. In addition, an event of default under the EXCO Resources Credit Agreement would constitute an event of default under our other debt agreements, including the agreements governing the 1.5 Lien Notes, the 1.75 Lien Term Loans, the 2018 Notes and the 2022 Notes, and would allow the lenders under such debt agreements to accelerate the outstanding amount of such debt. If any of our debt under the EXCO Resources Credit Agreement, the 1.5 Lien Notes, the 1.75 Lien Term Loans, the 2018 Notes and the 2022 Notes is accelerated, we would not have sufficient Liquidity to repay such indebtedness and would be forced to seek protection under the United States Bankruptcy Code.

~~Unless we are able to amend our debt agreements, we~~these financial forecasts will not be ~~able to make~~accurate. In our ~~next interest payment on~~case, the ~~1.75 Lien Term Loans on December 20, 2017.~~

Our next quarterly interest payment of approximately $26.9 million (based on the PIK Payment interest rate of 15.0%) for our 1.75 Lien Term Loans is due December 20, 2017, and is required to be paid in-kind pursuant to the terms of the indenture governing the 1.5 Lien Notes. Our ability to make PIK Payments in common shares is subject to a Resale Registration Statement being declared effective by the SEC. As of the date of the filing of this Quarterly Report on Form 10-Q, the Resale Registration Statement has not been declared effective and there is no assurance weforecasts will be ~~able to satisfy this condition.~~

~~The amount of PIK Payments made~~even more speculative than normal, because they may involve fundamental changes in additional 1.5 Lien Notes or 1.75 Lien Term Loans is subject to incurrence covenants within our debt agreements that limit our aggregate secured indebtedness to $1.2 billion. This amount is reduced dollar-for-dollar to the extent that we incur any additional secured indebtedness, including PIK Payments in additional indebtedness. Our ability to make future PIK Payments in additional indebtedness is limited to $6.9 million. Furthermore, the agreement governing the 1.75 Lien Term Loans restricts our ability to pay interest in cash, unless we have liquidity, on a pro forma basis, of at least $175.0 million.

As a result of the foregoing, unless we amend our debt agreements or obtain a waiver or other forbearance from certain lenders, we will not be able to make our next interest payment on the 1.75 Lien Term Loans on December 20, 2017. If we cannot make scheduled payments on our debt, we will be in default and holdersnature of our outstanding notes and loans could declare all outstanding principal and interest to be due and payable, the lenders under the EXCO Resources Credit Agreement could terminate their commitments to loan money, andcapital structure. Accordingly, we expect that our secured lenders could foreclose against the assets securing their borrowings. Any event of default may cause a default or accelerate our obligations with respect to unsecured indebtedness, including our 2018 Notes and 2022 Notes, which could adversely affect our business,actual financial condition and results of ~~operations.~~operations will differ, perhaps materially,

~~We may fail to comply with the standards for the continued listing of our common stock on the NYSE. If~~from what we fail to comply with these continued listing standards our common shares may be delisted from the NYSE, which could result in reductions to the price of our common stock and would make it more difficult to trade our common stock.

The continued listing of our common shares on the NYSE is subject to our compliance with a number of standards. On August 10, 2017, the Company was notified by the NYSE that it was not in compliance with the continued listing standards set forth in Section 802.01B of the NYSE’s Listed Company Manual because the Company’s average global market capitalization fell below $50 million over a trailing consecutive 30 trading-day period while its shareholders’ equity was less than $50 million.

On September 22, 2017 we submitted a business plan to the NYSE setting forth how we intend to regain compliance with the NYSE's market capitalization listing standard, and, on November 2, 2017, the NYSE accepted our business plan. If we fail to comply, or regain compliance with, the continued listing standards of the NYSE by February 10, 2019, it will result in a delisting of our common shares from the NYSE. In addition, if our market capitalization falls below $15 million for a 30 trading-day period or our share price falls to an abnormally low level, the NYSE may immediately suspend trading and commence delisting of our common shares.

~~There~~have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will ~~continue~~occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to ~~meet the continued listing standards of the NYSE. The delisting of our common shares from the NYSE~~materialize as anticipated could ~~result in further reductions in our share price, would substantially limit the liquidity of our common shares, and would~~ materially adversely affect the successful execution of any plan of reorganization.

Upon emergence from bankruptcy, the composition of our board of directors will change significantly.

The composition of our board of directors is expected to change significantly following the Chapter 11 Cases. Any new directors may have different backgrounds, experiences and perspectives from those individuals who previously served on the board and, thus, may have different views on the issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.

Our oil production in the South Texas region may be curtailed if we are not able to find an operational or commercial solution for the associated natural gas production

In our South Texas region, the primary purchaser of our natural gas allegedly terminated a long-term natural gas sales contract on May 31, 2017. As a result, our ability to ~~raise capital~~transport or ~~pursue strategic restructuring, refinancing~~sell the natural gas from this region continues to be limited due to the existing infrastructure and we may experience significant curtailments of production in the future if we cannot find an operational or ~~other transactions. Delisting~~commercial solution. After the alleged termination of the long-term natural gas sales contract, we have either sold natural gas on short-term sales contracts or flared natural gas in order to avoid significant curtailments of our oil production. However, our ability and the costs associated with entering into natural gas sales contracts in the future are highly uncertain.

As described in “Item 1. Legal Proceedings”, we have submitted a request to the Texas Railroad Commission for an extension of the permits to continue the aforementioned flaring of natural gas for up to two years, the maximum time allowable. If the Flaring Application is denied or, in the future, we are unable, for any sustained period, to secure acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut-in or curtail production of both oil and natural gas from the ~~NYSE could also have other negative~~affected wells in the South Texas region. Any such shut-in or curtailment or an inability to obtain acceptable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our cash flows and results of operations. We continue to evaluate alternatives, including construction of a Company-owned gathering system or the ~~potential loss~~negotiation of ~~confidence by institutional investors.~~a new gathering agreement.


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

Recent ~~Sales~~sales of ~~Unregistered Equity Securities~~unregistered equity securities

There were no sales of unregistered equity securities during the quarter ended September 30, ~~2017~~2018 that were not previously reported on a Current Report on Form 8-K.

Issuer repurchases of common shares

~~The following table details our~~

We did not repurchase ofany common shares ~~for~~during the ~~three months~~quarter ended September 30, ~~2017:~~2018.

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, 2017 - July 31, 2017 —
$ —
—
$ 192.5
August 1, 2017 - August 31, 2017 —
—
—
192.5
September 1, 2017 - September 30, 2017 —
—
—
192.5
Total —
$ —
—


~~(1)~~Item 3.	~~On July 19, 2010, we announced a $200.0 million share repurchase program.~~Defaults upon Senior Securities

As described herein, the commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the following debt instruments:

EXCO Resources Credit Agreement;

1.5 Lien Notes;

1.75 Lien Term Loans;

2018 Notes; and

2022 Notes.

In addition, we were in default under the Second Lien Term Loans as a result of our failure to make interest payments. For additional information, please see "Note 1. Organization and basis of presentation" and “Note 8. Debt” in the Notes to our Condensed Consolidated Financial Statements.


Item 6.	Exhibits



~~Exhibit~~
Exhibit Number		Description of Exhibits

~~2.1#~~	Purchase and Sale Agreement, dated as of April 7, 2017, by and among EXCO Operating Company, LP, EXCO Land Company LLC and VOG Palo Verde LP, filed on August 2, 2017 as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-219641) and incorporated by reference herein.

~~2.2#~~	First Amendment to Purchase and Sale Agreement, dated as of May 31, 2017, by and among EXCO Operating Company, LP, EXCO Land Company LLC and VOG Palo Verde LP, filed on August 2, 2017 as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-219641) and incorporated by reference herein.
3.1
~~2.3#~~	Second Amendment to Purchase and Sale Agreement, dated as of June 20, 2017, by and among EXCO Operating Company, LP, EXCO Land Company LLC and VOG Palo Verde LP, filed on August 2, 2017 as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-219641) and incorporated by reference herein.

~~2.4#~~	~~Agreement to Terminate Purchase and Sale Agreement, dated as of August 14, 2017, by and between EXCO Operating Company, LP, EXCO Land Company, LLC and VOG Palo Verde LP, filed herewith.~~

~~3.1~~	Amended and Restated Certificate of Formation of EXCO Resources, Inc., as amended through June 2, 2017, filed on August 2, 2017 as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-219641) 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 (File No. 001-32743), 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		Instrument of Resignation, Appointment and Acceptance, dated as of December 15, 2017, by and among EXCO Resources, Inc., Wilmington Trust, National Association and Wilmington Savings Fund Society, FSB filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated December 15, 2017 and filed December 21, 2017 and incorporated by reference herein.

4.9		~~4.8~~Instrument of Appointment and Acceptance, dated as of January 23, 2018, by and among EXCO Resources, Inc., Phoenix Investment Advisers LLC and GLAS Trust Company LLC filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 19, 2018 and filed January 25, 2018 and incorporated by reference herein.

4.10		Indenture, dated as of March 15, 2017, by and among EXCO Resources, Inc., as issuer, certain of its subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee and collateral trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~4.9~~ 4.11		First Supplemental Indenture, dated as of April 4, 2017, by and among EXCO Resources, Inc., as issuer, certain of its subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee and collateral trustee, filed on May 10, 2017 as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 and incorporated by reference herein.


~~4.10~~
4.12		Second Supplemental Indenture, dated as of April 14, 2017, by and among EXCO Resources, Inc., as issuer, certain of its subsidiaries, as guarantors, and Wilmington Trust, National Association, as trustee and collateral trustee, filed on May 10, 2017 as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 and incorporated by reference herein.

~~4.11~~ 4.13		Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Registration Statement on Form S-3, filed on December 17, 2013 and incorporated by reference herein.

~~4.12~~ 4.14		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-l (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein.

~~4.13~~ 4.15		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.

~~4.14~~ 4.16		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.

~~4.15~~ 4.17		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.

~~4.16~~ 4.18		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.

~~4.17~~ 4.19		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.

~~4.18~~	Registration Rights Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc. and the investors specified on the signatures thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~4.19~~	~~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.~~
4.20
~~4.20~~	~~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.~~

~~4.21~~	~~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.~~



~~4.22~~	~~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.~~

~~4.23~~	Form of Financing Warrant, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~4.24~~ 4.21		Form of Commitment Fee Warrant, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~4.25~~ 4.22		Form of Amendment Fee Warrant, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 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		~~10.5~~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 Quarterly Report on Form 10-Q (File No. 001-32743) for the Quarter Ended June 30, 2013 filed on August 7, 2013 and incorporated by reference herein.*

10.6		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~~ 10.7		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~~ 10.8		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~~ 10.9		Form of Performance-Based Share Unit Agreement for Named Executive Officers for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 1, 2015 and filed on July 8, 2015 and incorporated by reference herein.*

~~10.9~~ 10.10		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~~ 10.11		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~~ 10.12		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.*

10.13		~~10.12~~EXCO Resources, Inc. Severance Plan effective November 10, 2015, filed as an Exhibit to EXCO’s Annual Report on Form 10-K/A for 2017 filed on April 30, 2018 and incorporated by reference herein.

10.14		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.*


10.15
~~10.13~~	Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K (File No. 001-32743) for 2009 filed on February 24, 2010 and incorporated by reference herein.*

~~10.14~~ 10.16		Amendment Number Two to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of May 22, 2014, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 22, 2014 and filed on May 29, 2014 and incorporated by reference herein.*

~~10.15~~ 10.17		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.*

10.18		~~10.16~~Amendment Number Four to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., effective as of November 28, 2017, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 28, 2017 and filed on December 4, 2017 and incorporated by reference herein.*

10.19		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 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.




~~10.17~~ 10.20		Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.*

~~10.18~~ 10.21		Amendment Number Two to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of October 6, 2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated October 6, 2011 and filed on October 7, 2011 and incorporated by reference herein.*

~~10.19~~ 10.22		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~~EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 11, 2013 and filed on June 12, 2013 and incorporated by reference herein.*

10.23		EXCO Re~~10.20~~sources, Inc. 2017-2018 Key Employee Incentive Plan, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2017 filed on November 7, 2017 and incorporated by reference herein.*

10.24		Form of ~~Restricted Stock Award~~Retention Bonus Agreement for Key Employees, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2017 filed on November 7, 2017 and incorporated by reference herein.*

10.25		Form of Incentive Payment Agreement, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended ~~June~~September 30, ~~2013~~2017 filed on ~~August~~November 7, ~~2013~~2017 and incorporated by reference herein.*

~~10.21~~	EXCO Resources, Inc. 2017-2018 Key Employee Incentive Plan, filed herewith.*

~~10.22~~	Form of Retention Bonus Agreement for Key Employees, filed herewith.*
10.26
~~10.23~~	Form of Incentive Payment Agreement, filed herewith.*

~~10.24~~	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.

~~10.25~~ 10.27		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.

~~10.26~~ 10.28		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.

~~10.27~~ 10.29		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.

~~10.28~~ 10.30		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.


10.31
~~10.29~~	Amendment to Joint Development Agreement, dated October 14, 2014, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporated by reference herein.

~~10.30~~ 10.32		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.

~~10.31~~ 10.33		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.


~~10.32~~
10.34		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.

~~10.33~~ 10.35		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.

~~10.34~~ 10.36		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.

~~10.35~~ 10.37		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.

~~10.36~~ 10.38		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.

~~10.37~~ 10.39		Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and EXCO Holding (PA), Inc, filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

~~10.38~~	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.

~~10.39~~ 10.40		~~Amended and Restated Credit~~Forbearance 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 Current Report on Form 8-K, dated as of August 19, 2013 and filed on August 23, 2013 and incorporated by reference herein.

~~10.40~~	First Amendment to Amended and Restated Credit Agreement, dated as of August 28, 2013, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lender parties thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated as of August 28, 2013 and filed on September 4, 2013 and incorporated by reference herein.

~~10.41~~	~~Second Amendment to Amended and Restated Credit Agreement, dated as of July 14, 2014,~~December 20, 2017, by and among EXCO Resources, Inc., ~~as Borrower, certain subsidiaries of Borrower, as Guarantors,~~ the ~~Lenders~~subsidiary guarantors 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~~administrative agent and ~~filed on July 18, 2014 and incorporated by reference herein.~~



~~10.42~~	~~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 RBL Supporting 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.~~

~~10.43~~	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 Form 8-K, dated as of February 6, 2015 and filed on February 12, 2015 and incorporated by reference herein.

~~10.44~~	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.

~~10.45~~	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.

~~10.46~~	~~Seventh Amendment to Amended and Restated Credit Agreement, dated as of March~~December 15, 2017 ~~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 March 15, 2017 and filed on March 15,~~December 21, 2017 and incorporated by reference herein.

~~10.47~~	Eighth Amendment to Amended and Restated Credit Agreement, dated as of September 29, 2017, by and among EXCO Resources, Inc., certain of its subsidiaries, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of September 29, 2017 and filed on October 5, 2017 and incorporated by reference herein.

~~10.48~~ 10.41		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 as an Exhibit to EXCO’s Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2016 filed on November 2, 2016 and incorporated by reference herein.

~~10.49~~ 10.42		Limited Consent, dated as of December 30, 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 as an Exhibit to EXCO's Current Report on Form 8- K, dated as of December 30, 2016 and filed on January 6, 2017 and incorporated by reference herein.

~~10.50~~ 10.43		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.

~~10.51~~ 10.44		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 filed on November 11, 2015 and incorporated by reference herein.

~~10.52~~ 10.45		First Amendment to Term Loan Credit Agreement, dated as of March 15, 2017, 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 March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~10.53~~ 10.46		1.75 Lien Term Loan Credit Agreement, dated as of March 15, 2017, 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 March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.


~~10.54~~
10.47		First Amendment to 1.75 Lien Term Loan Credit Agreement, dated as of April 4, 2017, 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 on May 10, 2017 as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 and incorporated by reference herein.




~~10.55~~ 10.48		Second Amendment to 1.75 Lien Term Loan Credit Agreement, dated as of April 14, 2017, 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 on May 10, 2017 as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2017 and incorporated by reference herein.

10.49		~~10.56~~Forbearance Agreement, dated as of December 19, 2017, by and among EXCO Resources, Inc., the subsidiary guarantors party thereto, and the 1.75L Supporting Lenders filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated December 15, 2017 filed December 21, 2017 and incorporated by reference herein.

10.50		Forbearance Agreement, dated as of December 19, 2017, by and among EXCO Resources, Inc., the subsidiary guarantors party thereto, and the Supporting Holders filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated December 15, 2017 filed December 21, 2017 and incorporated by reference herein.

10.51		Intercreditor Agreement, dated as of October 26, 2015 and amended as of March 15, 2017, by and among EXCO Resources, Inc., JPMorgan Chase Bank, N.A., as original priority lien agent, and Wilmington Trust, National Association, as second lien collateral trustee and original third lien collateral agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~10.57~~ 10.52		Amended and Restated Collateral Trust Agreement, dated as of October 26, 2015 and amended and restated as of March 15, 2017, by and among EXCO Resources, Inc., the grantors and guarantors from time to time party thereto, Wilmington Trust, National Association, as administrative agent and collateral trustee, and the other parity lien debt representatives from time to time party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~10.58~~ 10.53		Collateral Trust Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc., the grantors and guarantors from time to time party thereto, Wilmington Trust, National Association, as trustee under the second lien indenture and collateral trustee, and the other parity lien debt representatives from time to time party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~10.59~~	~~Form of Senior Note Purchase Agreement, 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.~~

~~10.60~~	Form of Follow-on Senior Note Purchase Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated as of October 30, 2015 and filed on November 2, 2015 and incorporated by reference herein.
10.54
~~10.61~~	1.5 Lien Note Purchase Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc., certain of its subsidiaries, and the purchaser signatories thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~10.62~~ 10.55		Second Lien Term Loan Purchase Agreement, dated as of March 15, 2017, by and among EXCO Resources, Inc., Hamblin Watsa Investment Counsel Ltd., as administrative agent under the Fairfax Second Lien Credit Agreement, Wilmington Trust, National Association, as administrative agent under the Exchange Second Lien Credit Agreement, and each of the other undersigned parties thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

~~10.63~~ 10.56		Amended and Restated Participation Agreement, dated July 25, 2016, by and among Admiral A Holding L.P., TE Admiral A Holding L.P., Colt Admiral A Holding L.P. and EXCO Operating Company, LP., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 25, 2016 and filed on July 27, 2016 and incorporated by reference herein.

~~10.64~~ 10.57		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,~~3, 2010 and filed on November 12, 2010 and incorporated by reference herein.

~~10.65~~ 10.58		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 (File No. 001-32743), dated November 15, 2013 and filed on November 21, 2013 and incorporated by reference herein.

~~10.66~~		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.*

~~10.67~~ 10.59	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.*

~~10.68~~ 10.60	EXCO Resources, Inc. 2017 Management Incentive Plan, dated April 3, 2017, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 3, 2017 and filed on April 7, 2017 and incorporated by reference herein.*




~~10.69~~	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.*
10.61
~~10.70~~	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.*

~~10.71~~	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.

~~10.72~~ 10.62		Acknowledgment of Amendment to Services and Investment Agreement, dated as of May 26, 2015, by and between EXCO Resources, Inc. and Energy Strategic Advisory Services LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated May 26, 2015 and filed on June 1, 2015 and incorporated by reference herein.

~~10.73~~ 10.63		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.

~~10.74~~ 10.64		Nomination Letter 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.

10.65		~~10.75~~Letter Agreement, dated as of November 9, 2017, by and between EXCO Resources, Inc. and Energy Strategic Advisory Services, LLC, filed as an Exhibit to EXCO's Annual Report on Form 10-K for 2017 filed on March 15, 2018 and incorporated by reference herein.

10.66		Form of Backstop Commitment Fee Election Letter, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 15, 2017 and filed on March 15, 2017 and incorporated by reference herein.

10.67		~~31.1~~Debtor-In-Possession Credit Agreement, dated as of January 22, 2018, among EXCO Resources, Inc., the Lenders party thereto, and Hamblin Watsa Investment Counsel Ltd., as Administrative Agent filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 19, 2018 filed January 25, 2018 and incorporated by reference herein.

10.68		Agreement Regarding Settlement, dated January 29, 2018, by and among EXCO Resources, Inc., EXCO Holding (PA), Inc., EXCO Resources (PA), LLC, EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, EXCO Operating Company, LP, EXCO Appalachia Midstream, LLC, BG US Production Company, LLC, BG North America, LLC, BG Production Company (PA), LLC, BG Production Company (WV), LLC and SWEPI LP filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein.

10.69		Settlement Agreement and Mutual Release, dated February 27, 2018, by and among EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, EXCO Resources (PA), LLC, BG Production Company (PA), LLC, BG Production Company (WV), LLC and SWEPI LP filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein.

10.70		Membership Interest (BG PA) Transfer Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, BG Production Company (PA), LLC and EXCO Production Company (PA), LLC filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein.

10.71		Membership Interest (BG WV) Transfer Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, BG Production Company (WV), LLC and EXCO Production Company (WV), LLC filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein.

10.72		Membership Interest (ERPA) Transfer Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, EXCO Resources (PA), LLC and EXCO Holding (PA), Inc. filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein.




10.73		Membership Interest (Midstream) Transfer Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, EXCO Appalachia Midstream, LLC and EXCO Holding (PA), Inc. filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein.

10.74		Termination and Release Agreement, dated February 27, 2018, by and among BG US Production Company, LLC, BG North America, LLC, BG Production Company (PA), LLC, BG Production Company (WV), LLC, EXCO Resources, Inc., EXCO Holding (PA), Inc., EXCO Resources (PA), LLC, EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, EXCO Operating Company, LP and EXCO Appalachia Midstream, LLC. filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 22, 2018 filed March 1, 2018 and incorporated by reference herein.

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

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

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

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Calculation Linkbase Document.

101.DEF		XBRL Taxonomy Definition Linkbase Document.

101.LAB		XBRL Taxonomy Label Linkbase Document.

101.PRE		XBRL Taxonomy Presentation Linkbase Document.

*		These exhibits are management contracts.

#	Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. EXCO Resources, Inc. hereby undertakes to furnish supplemental copies of any of the omitted schedules and exhibits upon request by the Securities and Exchange Commission.

SIGNATURES

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



		EXCO RESOURCES, INC.
		(Registrant)

Date:	November ~~7, 2017~~13, 2018	/s/ Harold L. Hickey
		Harold L. Hickey
		Chief Executive Officer and President
		(Principal Executive Officer)

		/s/ Tyler S. Farquharson
		Tyler S. Farquharson
		Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

		/s/ Brian N. Gaebe
		Brian N. Gaebe
		Chief Accounting Officer and Corporate Controller
		(Principal Accounting Officer)

6865



(dollars in thousands, except prices)	Volume Bbtu/Mbbl	Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2017
Natural gas:
Swaps:
Remainder of 2017	9,200	$	3.05	$	(3	)
2018	3,650	3.15		351
Collars:
Remainder of 2017	2,760			(59		)
Sold call		3.28
Purchased put		2.87
Total natural gas				$	289
Oil:
Swaps:
Remainder of 2017	46	$	50.00	$	(81	)
Total oil				$	(81	)
Total commodity derivative financial instruments				$	208



	September 30, 2017
(in thousands)	Carrying value			Deferred reduction in carrying value			Unamortized discount/deferred financing costs		Principal balance
EXCO Resources Credit Agreement	$	126,401		$	—		$	—	$	126,401
1.5 Lien Notes	172,030			—			144,928		316,958
1.75 Lien Term Loans	844,487			(154,171		)	18,610		708,926
Exchange Term Loan	23,543			(6,297		)	—		17,246
2018 Notes	131,271			—			305		131,576
2022 Notes	70,169			—			—		70,169
Deferred financing costs, net	(12,524		)	—			12,524		—
Total debt	$	1,355,377		$	(160,468	)	$	176,367	$	1,371,276



(in thousands)	Principal amount outstanding		Maturity date		Frequency of payment	Annual cash interest rate
EXCO Resources Credit Agreement	$	126,401	July 31, 2018		Monthly	⁽¹⁾
1.5 Lien Notes	316,958		March 20, 2022		Semi-annually	8.0%
1.75 Lien Term Loans	708,926		October 26, 2020		Quarterly	12.5%
Exchange Term Loan	17,246		October 26, 2020		Quarterly	12.5%
2018 Notes	131,576		September 15, 2018	��	Semi-annually	7.5%
2022 Notes	70,169		April 15, 2022		Semi-annually	8.5%
Total debt	$	1,371,276



	Nine Months Ended		October - December Forecast		Full Year Forecast
(in thousands)	September 30, 2017		2017		2017
Capital expenditures:
Development capital expenditures	$	91,133	$	57,867	$	149,000
Other (1)	16,176		1,824		18,000
Total	$	107,309	$	59,691	$	167,000



	NYMEX gas volume - Bbtu	Weighted average contract price per Mmbtu		NYMEX oil volume - Mbbl	Weighted average contract price per Bbl
Swaps:
Remainder of 2017	9,200	$	3.05	46	$	50.00
2018	3,650	3.15		—	—
Collars:
Remainder of 2017	2,760			—
Sold call		3.28			—
Purchased put		2.87			—



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, 2017 - July 31, 2017	—	$	—	—	$	192.5
August 1, 2017 - August 31, 2017	—	—		—	192.5
September 1, 2017 - September 30, 2017	—	—		—	192.5
Total	—	$	—	—