EXCO RESOURCES INC - FORM 10-Q

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EX-31.2 - CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 OF CFO - EXCO RESOURCES INC	exhibit312pfo5111.htm
EX-32.1 - CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 OF EXEC - EXCO RESOURCES INC	exhibit321pfopeo5111.htm
EX-31.1 - CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 OF EXEC - EXCO RESOURCES INC	exhibit311peo5111.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________



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

For the quarterly period ended September 30, 2015



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

For the transition period from to

Commission File Number 001-32743

______________________________

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

______________________________



Texas		74-1492779
(State of incorporation)		(I.R.S. Employer Identification No.)

12377 Merit Drive Suite 1700, LB 82 Dallas, Texas		75251
(Address of principal executive offices)		(Zip Code)

(214) 368-2084

(Registrant’s telephone number, including area code)

______________________________

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

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

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

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

The number of shares of common stock, par value $0.001 per share, outstanding as of October 22, 2015 was 283,052,106.

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EXCO RESOURCES, INC.

INDEX



PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at September 30, 2015 and December 31, 2014	2
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014	4
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014	5
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2015 and 2014	6
	Notes to Condensed Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
Item 4.	Controls and Procedures	47

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 6.	Exhibits	49
	Signatures	50

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PART I—FINANCIAL INFORMATION


Item 1.	Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS



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

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS



(in thousands, except per share and share data)	September 30, 2015			December 31, 2014
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	100,309		$	110,211
Revenues and royalties payable	129,101			152,651
Drilling advances	12,825			37,648
Accrued interest payable	22,504			26,265
Current portion of asset retirement obligations	1,769			1,769
Income taxes payable	—			—
Deferred income taxes	18,749			35,935
Derivative financial instruments	3			892
Total current liabilities	285,260			365,371
Long-term debt	1,545,106			1,446,535
Derivative financial instruments	30			—
Asset retirement obligations and other long-term liabilities	38,434			34,986
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,655,812 shares issued and 283,061,149 shares outstanding at September 30, 2015; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014	276			270
Additional paid-in capital	3,518,523			3,502,209
Accumulated deficit	(4,111,643		)	(2,984,860		)
Treasury shares, at cost; 594,663 shares at September 30, 2015 and 578,042 at December 31, 2014	(7,632		)	(7,615		)
Total shareholders’ equity	(600,476		)	510,004
Total liabilities and shareholders’ equity	$	1,268,354		$	2,356,896

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share data)	2015			2014			2015			2014
Revenues:
Oil	$	27,444		$	50,746		$	79,872		$	159,131
Natural gas	56,082			100,296			183,716			373,349
Total revenues	83,526			151,042			263,588			532,480
Costs and expenses:
Oil and natural gas operating costs	12,669			14,099			41,745			48,713
Production and ad valorem taxes	5,944			7,978			16,408			22,951
Gathering and transportation	23,743			25,822			74,243			76,473
Depletion, depreciation and amortization	52,013			64,913			176,160			201,441
Impairment of oil and natural gas properties	339,393			—			1,010,047			—
Accretion of discount on asset retirement obligations	574			709			1,698			2,085
General and administrative	13,393			14,059			41,227			50,901
Other operating items	(228		)	663			1,118			6,382
Total costs and expenses	447,501			128,243			1,362,646			408,946
Operating income (loss)	(363,975		)	22,799			(1,099,058		)	123,534
Other income (expense):
Interest expense, net	(27,761		)	(23,974		)	(80,822		)	(70,106		)
Gain (loss) on derivative financial instruments	37,348			42,844			54,427			(14,896		)
Other income	21			53			119			176
Equity income (loss)	(152		)	(153		)	(1,452		)	548
Total other income (expense)	9,456			18,770			(27,728		)	(84,278		)
Income (loss) before income taxes	(354,519		)	41,569			(1,126,786		)	39,256
Income tax expense	—			—			—			—
Net income (loss)	$	(354,519	)	$	41,569		$	(1,126,786	)	$	39,256
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(1.30	)	$	0.15		$	(4.14	)	$	0.15
Weighted average common shares outstanding	273,348			270,631			272,147			267,316
Diluted:
Net income (loss)	$	(1.30	)	$	0.15		$	(4.14	)	$	0.15
Weighted average common shares and common share equivalents outstanding	273,348			272,066			272,147			267,690

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



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

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)



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

See accompanying notes.

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EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.Organization and basis of presentation

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

•East Texas and North Louisiana

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

•South Texas

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

•Appalachia

The Appalachia region is primarily comprised of Marcellus shale assets as well as shallow conventional assets in other formations. We have a joint venture with BG Group covering our shallow conventional assets and Marcellus shale assets in the Appalachia region ("Appalachia JV"). EXCO and BG Group each own an undivided 50% interest in the Appalachia JV and a 49.75% working interest in the Appalachia JV's properties. The remaining 0.5% working interest is held by a jointly owned operating entity ("OPCO") that operates the Appalachia JV's properties. We own a 50% interest in OPCO.

The accompanying Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the nine months ended September 30, 2015 and 2014 are for EXCO and its subsidiaries. The condensed consolidated financial statements and related footnotes are presented in accordance with generally accepted accounting principles in the United States ("GAAP"). Certain reclassifications have been made to prior period information to conform to current period presentation.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO at September 30, 2015 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in EXCO's Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on February 25, 2015, as amended by Amendment No. 1 to Annual Report on Form 10-K/A, filed with the SEC on April 10, 2015 ("2014 Form 10-K").

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

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2.Significant accounting policies

We consider significant accounting policies to be those related to our estimates of proved reserves, oil and natural gas properties, derivatives, business combinations, share-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in the 2014 Form 10-K.

Goodwill

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

Recent accounting pronouncements

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. We currently recognize debt issuance costs as assets on our balance sheet. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. ASU 2015-03 is effective for annual and interim periods beginning after December 15, 2015 and early adoption is permitted. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ("ASU 2015-15"). ASU 2015-15 clarifies that the SEC would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset on the balance sheet. We plan to adopt ASU 2015-03 and ASU 2015-15 in the fourth quarter of 2015. The adoption of ASU 2015-03 and ASU 2015-15 will result in certain reclassifications of debt issuance costs on our balance sheets.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments ("ASU 2015-16"). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this update require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for annual and interim periods beginning after December 15, 2015 and early adoption is permitted. We will apply this guidance to business combinations, when applicable, occurring after the effective date of ASU 2015-16.

3.Acquisitions

Eagle Ford acquisition program

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

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

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

4.Asset retirement obligations

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



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

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

5.Oil and natural gas properties

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. We review our unproved oil and natural gas property costs on a quarterly basis to assess for impairment or the need to transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. As a result of our evaluation, we impaired approximately $84.9 million of unproved properties which were transferred to the depletable portion of the full cost pool during the nine months ended September 30, 2015. The impairment was recorded to reflect the estimated fair value of our undeveloped properties as a result of the decline in oil and natural gas prices. See "Note 8. Fair value measurements" for further discussion. There were no impairments of unproved properties during the nine months ended September 30, 2014.

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

The ceiling test for each period presented was based on the following average spot prices, in each case adjusted for quality factors and regional differentials to derive estimated future net revenues. Prices presented in the table below are the trailing 12 month simple average spot prices at the first of the month for natural gas at Henry Hub ("HH") and West Texas Intermediate ("WTI") crude oil at Cushing, Oklahoma. The fluctuations demonstrate the volatility in oil and natural gas prices

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



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

We recognized impairments to our proved oil and natural gas properties of $339.4 million and $1.0 billion for the three and nine months ended September 30, 2015, respectively. The impairments were primarily due to the decline in oil and natural gas prices. We did not recognize impairments to our proved oil and natural gas properties for the three and nine months ended September 30, 2014. We may incur additional impairments to our oil and natural gas properties in 2015 if oil and natural gas prices do not increase. The possibility and amount of any future impairments is difficult to predict, and will depend, in part, upon future oil and natural gas prices to be utilized in the ceiling test, estimates of proved reserves and future capital expenditures and operating costs.

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

6.Earnings (loss) per share

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



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

Diluted net income (loss) per common share for the three and nine months ended September 30, 2015 and 2014 is computed in the same manner as basic income (loss) per share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which include stock options, restricted share units, restricted share awards and warrants, whether exercisable or not. The computation of diluted earnings (loss) per share excluded 36,157,630 and 13,122,425 antidilutive share equivalents for the three months ended September 30, 2015 and 2014, respectively, and 21,200,285 and 13,668,594 antidilutive share equivalents for the nine months ended September 30, 2015 and 2014, respectively.

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7.Derivative financial instruments

Our primary objective in entering into derivative financial instruments is to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow from operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instruments consists of non-cash income or expense due to changes in the fair value. Cash losses or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings.

The table below outlines the classification of our derivative financial instruments on our Condensed Consolidated Balance Sheets and their financial impact on our Condensed Consolidated Statements of Operations.

Fair Value of Derivative Financial Instruments



(in thousands)	September 30, 2015			December 31, 2014
Derivative financial instruments - Current assets	$	55,000		$	97,278
Derivative financial instruments - Long-term assets	9,007			2,138
Derivative financial instruments - Current liabilities	(3		)	(892		)
Derivative financial instruments - Long-term liabilities	(30		)	—
Net derivative financial instruments	$	63,974		$	98,524

Effect of Derivative Financial Instruments



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

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

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

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

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

Call options: These contracts give our trading counterparties the right, but not the obligation, to buy an agreed quantity of oil or natural gas from us at a certain time and price in the future. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess. If the market price settles below the fixed price of the call option, no payment is due from either party. In exchange for selling this option, we received upfront proceeds which we used to obtain a higher fixed price on our swaps. These transactions were conducted contemporaneously with a single counterparty and resulted in a net cashless transaction.

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

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We place our derivative financial instruments with the financial institutions that are lenders under our credit agreement that we believe have high quality credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with counterparties to our derivative financial instruments that allow us to offset our asset position with our liability position in the event of a default by the counterparty.

The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments as of September 30, 2015:



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

At December 31, 2014, we had outstanding swap, call option and three-way collar contracts covering 42,888 Mmmbtu, 20,075 Mmmbtu and 38,355 Mmmbtu, respectively, of natural gas and we had outstanding swap, basis swap and call option contracts covering 1,095 Mbbls, 91 Mbbls and 365 Mbbls, respectively, of oil.

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

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

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8.Fair value measurements

We value our derivatives and other financial instruments according to FASB ASC 820, Fair Value Measurements and Disclosures, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability ("exit price") in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.

We categorize the inputs used in measuring fair value into a three-tier fair value hierarchy. These tiers include:

Level 1 – Observable inputs, such as quoted market prices in active markets, for substantially identical assets and liabilities.

Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring development of fair value assumptions by management.

Fair value of derivative financial instruments

The fair value of our derivative financial instruments may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers. During the nine months ended September 30, 2015 and 2014 there were no changes in the fair value level classifications. The following table presents a summary of the estimated fair value of our derivative financial instruments as of September 30, 2015 and December 31, 2014.



	September 30, 2015
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	63,974	$	—	$	63,974
	December 31, 2014
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	98,524	$	—	$	98,524

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

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

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

Natural gas derivatives. Our natural gas derivatives are swap, three-way collar and call option contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap and option contracts. The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH for natural gas swaps, (iii) the applicable credit-adjusted risk-free rate curve, as described above, and (iv) the implied rate of volatility inherent in the option contracts. The implied rates of volatility were determined based on average HH natural gas prices.

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

Fair value of other financial instruments

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

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

The estimated fair values of our 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and our 8.5% senior unsecured notes due April 15, 2022 ("2022 Notes") have been calculated based on market quotes and are presented below.



	September 30, 2015
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	225,000	$	—	$	—	$	225,000
2022 Notes	131,840		—		—		131,840
	December 31, 2014
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	558,750	$	—	$	—	$	558,750
2022 Notes	373,500		—		—		373,500

Other fair value measurements

As discussed in "Note 5. Oil and natural gas properties", we assess our unproved oil and natural gas properties for potential impairment due to an other than temporary trend that would negatively impact the fair value. The continued depressed oil and natural gas prices as well as longer-term commodity price outlooks provided indications of possible impairment. During the nine months ended September 30, 2015, we impaired approximately $84.9 million of unproved properties to reduce the carrying value to the fair value. These impairment charges were transferred to the depletable portion of the full cost pool. We calculated the estimated fair value of our unproved properties based on the average cost per undeveloped acre or the discounted cash flow models from our internally generated oil and natural gas reserves as of September 30, 2015. The pricing utilized in the discounted cash flow models was based on NYMEX futures, adjusted for basis differentials. Our oil and natural gas properties were further discounted based on the classification of the underlying reserves and management's assessment of recoverability. The fair value measurements utilized include significant unobservable inputs that are considered to be Level 3 within the fair value hierarchy. These unobservable inputs include management's estimates of reserve quantities, commodity prices, operating costs, development costs, discount factors and other risk factors applied to the future cash flows. The average cost per undeveloped acre was based on recent comparable market transactions in each region.

9.Debt

Our total debt is summarized as follows:



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

Terms and conditions of our debt obligations are discussed below.

EXCO Resources Credit Agreement

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

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

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


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


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


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

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

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

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

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

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

Second Lien Term Loans

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

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


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


•	prepay, redeem or repurchase certain debt;


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


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


•	enter into transactions with affiliates;


•	consolidate, merge or dispose of assets;


•	incur liens; and


•	enter into sale/leaseback transactions.

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

•

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


•	second lien debt in excess of $700.0 million;


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

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


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


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


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


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

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

2018 Notes

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

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

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

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


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


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


•	make certain investments;


•	create liens on our assets;


•	enter into sale/leaseback transactions;


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


•	engage in transactions with our affiliates;


•	transfer or issue shares of stock of subsidiaries;


•	transfer or sell assets; and


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

2022 Notes

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

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

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

10.Income taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial deferred tax assets primarily due to losses arising from impairments to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances increased $435.8 million for the nine months ended September 30, 2015. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $1.3 billion which have fully offset our net deferred tax assets as of September 30, 2015. The valuation allowances will continue to be recognized until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowances do not impact future utilization of the underlying tax attributes.

11.Related party transactions

OPCO

OPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. We did not advance any funds to OPCO during the three or nine months ended September 30, 2015 or 2014. OPCO may distribute any excess cash equally between us and BG Group when its operating cash flows are sufficient to meet its capital requirements. There are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the three and nine months ended September 30, 2015 and 2014, these transactions included the following:

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

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



(in thousands)	September 30, 2015		December 31, 2014
Amounts due to EXCO (1)	$	2,171	$	2,799
Amounts due from EXCO (1)	8,341		—


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

Services and investment agreement

On September 8, 2015, we closed the services and investment agreement with Energy Strategic Advisory Services LLC ("ESAS"), a wholly-owned subsidiary of Bluescape Resources Company LLC ("Bluescape"). At the closing, C. John Wilder, Executive Chairman of Bluescape, was appointed as a member of our Board of Directors and as Executive Chairman of the Board of Directors. See "Note 12. Services and Investment Agreement" for further information.

Second lien term loans

Hamblin Watsa Investment Counsel Ltd. (“Hamblin Watsa”), a wholly owned subsidiary of Fairfax, is the administrative agent of the Fairfax Term Loan and certain affiliates of Fairfax are lenders under the Fairfax Term Loan. Samuel A. Mitchell, a member of the our Board of Directors, is a Managing Director of Hamblin Watsa and a member of Hamblin Watsa’s investment committee, which consists of seven members that manage the investment portfolio of Fairfax. Based on filings with the SEC, Fairfax is the beneficial owner of approximately 6.2% of our outstanding common shares. See “Note 9. Debt” for further information.

12.Services and Investment Agreement

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

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

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

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

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

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

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

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

13.Condensed consolidating financial statements

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

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

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


•	Resources;


•	the Guarantor Subsidiaries;


•	the Non-Guarantor Subsidiaries;


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


•	EXCO on a consolidated basis.

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

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

September 30, 2015



(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	34,990		$	(14,479	)	$	—	$	—		$	20,511
Restricted cash	1,500			19,954			—		—			21,454
Other current assets	66,089			97,428			—		—			163,517
Total current assets	102,579			102,903			—		—			205,482
Equity investments	—			—			55,036		—			55,036
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			119,046			—		—			119,046
Proved developed and undeveloped oil and natural gas properties	330,776			2,903,601			—		—			3,234,377
Accumulated depletion	(330,776		)	(2,258,194		)	—		—			(2,588,970		)
Oil and natural gas properties, net	—			764,453			—		—			764,453
Other property and equipment, net	718			27,084			—		—			27,802
Investments in and advances to affiliates, net	832,810			—			—		(832,810		)	—
Deferred financing costs, net	24,670			—			—		—			24,670
Derivative financial instruments	9,007			—			—		—			9,007
Goodwill	13,293			149,862			—		—			163,155
Deferred income taxes	18,749			—			—		—			18,749
Total assets	$	1,001,826		$	1,044,302		$	55,036	$	(832,810	)	$	1,268,354
Liabilities and shareholders' equity
Current liabilities	$	56,967		$	228,293		$	—	$	—		$	285,260
Long-term debt	1,545,106			—			—		—			1,545,106
Other long-term liabilities	229			38,235			—		—			38,464
Payable to parent	—			2,240,498			—		(2,240,498		)	—
Total shareholders' equity	(600,476		)	(1,462,724		)	55,036		1,407,688			(600,476		)
Total liabilities and shareholders' equity	$	1,001,826		$	1,044,302		$	55,036	$	(832,810	)	$	1,268,354

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2014



(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	86,837		$	(40,532	)	$	—	$	—		$	46,305
Restricted cash	—			23,970			—		—			23,970
Other current assets	110,145			150,346			—		—			260,491
Total current assets	196,982			133,784			—		—			330,766
Equity investments	—			—			55,985		—			55,985
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			276,025			—		—			276,025
Proved developed and undeveloped oil and natural gas properties	335,838			3,516,235			—		—			3,852,073
Accumulated depletion	(330,771		)	(2,083,690		)	—		—			(2,414,461		)
Oil and natural gas properties, net	5,067			1,708,570			—		—			1,713,637
Other property and equipment, net	1,269			23,375			—		—			24,644
Investments in and advances to affiliates, net	1,746,931			—			—		(1,746,931		)	—
Deferred financing costs, net	30,636			—			—		—			30,636
Derivative financial instruments	2,138			—			—		—			2,138
Goodwill	13,293			149,862			—		—			163,155
Deferred income taxes	35,935			—			—		—			35,935
Total assets	$	2,032,251		$	2,015,591		$	55,985	$	(1,746,931	)	$	2,356,896
Liabilities and shareholders' equity
Current liabilities	$	75,441		$	289,930		$	—	$	—		$	365,371
Long-term debt	1,446,535			—			—		—			1,446,535
Other long-term liabilities	271			34,715			—		—			34,986
Payable to parent	—			2,058,683			—		(2,058,683		)	—
Total shareholders' equity	510,004			(367,737		)	55,985		311,752			510,004
Total liabilities and shareholders' equity	$	2,032,251		$	2,015,591		$	55,985	$	(1,746,931	)	$	2,356,896

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2015



(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	83,526		$	—		$	—	$	83,526
Costs and expenses:
Oil and natural gas production	7			18,606			—			—		18,613
Gathering and transportation	—			23,743			—			—		23,743
Depletion, depreciation and amortization	229			51,784			—			—		52,013
Impairment of oil and natural gas properties	1,372			338,021			—			—		339,393
Accretion of discount on asset retirement obligations	—			574			—			—		574
General and administrative	(2,345		)	15,738			—			—		13,393
Other operating items	(3		)	(225		)	—			—		(228		)
Total costs and expenses	(740		)	448,241			—			—		447,501
Operating income (loss)	740			(364,715		)	—			—		(363,975		)
Other income (expense):
Interest expense, net	(27,761		)	—			—			—		(27,761		)
Gain on derivative financial instruments	37,348			—			—			—		37,348
Other income	14			7			—			—		21
Equity loss	—			—			(152		)	—		(152		)
Net loss from consolidated subsidiaries	(364,860		)	—			—			364,860		—
Total other income (expense)	(355,259		)	7			(152		)	364,860		9,456
Loss before income taxes	(354,519		)	(364,708		)	(152		)	364,860		(354,519		)
Income tax expense	—			—			—			—		—
Net loss	$	(354,519	)	$	(364,708	)	$	(152	)	$	364,860	$	(354,519	)

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2014



(in thousands)	Resources			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	173		$	138,983	$	11,886		$	—		$	151,042
Costs and expenses:
Oil and natural gas production	(31		)	16,823		5,285			—			22,077
Gathering and transportation	1			24,697		1,124			—			25,822
Depletion, depreciation and amortization	658			59,392		4,863			—			64,913
Accretion of discount on asset retirement obligations	4			532		173			—			709
General and administrative	(3,059		)	16,211		907			—			14,059
Other operating items	(103		)	779		(13		)	—			663
Total costs and expenses	(2,530		)	118,434		12,339			—			128,243
Operating income (loss)	2,703			20,549		(453		)	—			22,799
Other income (expense):
Interest expense, net	(23,300		)	—		(674		)	—			(23,974		)
Gain on derivative financial instruments	40,835			—		2,009			—			42,844
Other income	31			16		6			—			53
Equity loss	—			—		(153		)	—			(153		)
Net income from consolidated subsidiaries	21,300			—		—			(21,300		)	—
Total other income	38,866			16		1,188			(21,300		)	18,770
Income before income taxes	41,569			20,565		735			(21,300		)	41,569
Income tax expense	—			—		—			—			—
Net income	$	41,569		$	20,565	$	735		$	(21,300	)	$	41,569

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2015



(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	4		$	263,584		$	—		$	—	$	263,588
Costs and expenses:
Oil and natural gas production	30			58,123			—			—		58,153
Gathering and transportation	—			74,243			—			—		74,243
Depletion, depreciation and amortization	753			175,407			—			—		176,160
Impairment of oil and natural gas properties	8,263			1,001,784			—			—		1,010,047
Accretion of discount on asset retirement obligations	4			1,694			—			—		1,698
General and administrative	(6,569		)	47,796			—			—		41,227
Other operating items	2,065			(947		)	—			—		1,118
Total costs and expenses	4,546			1,358,100			—			—		1,362,646
Operating loss	(4,542		)	(1,094,516		)	—			—		(1,099,058		)
Other income (expense):
Interest expense, net	(80,822		)	—			—			—		(80,822		)
Gain on derivative financial instruments	54,427			—			—			—		54,427
Other income	87			32			—			—		119
Equity loss	—			—			(1,452		)	—		(1,452		)
Net loss from consolidated subsidiaries	(1,095,936		)	—			—			1,095,936		—
Total other income (expense)	(1,122,244		)	32			(1,452		)	1,095,936		(27,728		)
Loss before income taxes	(1,126,786		)	(1,094,484		)	(1,452		)	1,095,936		(1,126,786		)
Income tax expense	—			—			—			—		—
Net loss	$	(1,126,786	)	$	(1,094,484	)	$	(1,452	)	$	1,095,936	$	(1,126,786	)

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2014



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

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2015



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

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2014



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

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

Forward-looking statements

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


•	our future financial and operating performance and results;


•	our business strategy;


•	market prices;


•	our future use of derivative financial instruments; and


•	our plans and forecasts.

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


•	fluctuations in the prices of oil and natural gas;


•	the availability of oil and natural gas;


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


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


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


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


•	geological concentration of our reserves;


•	risks associated with drilling and operating wells;


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


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


•	cash flow and liquidity;


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


•	availability of drilling and production equipment;


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


•	marketing of oil and natural gas;


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


•	title to our properties;


•	litigation;


•	competition;


•	our ability to attract and retain key personnel;


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


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


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


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


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


•	potential acts of terrorism;

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


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


•	fluctuations in interest rates;


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


•	our ability to execute the business strategies and other corporate actions developed in connection with EXCO's strategic improvement plan.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on any forward-looking statements. When considering our forward-looking statements, keep in mind the cautionary statements in this Quarterly Report on Form 10-Q, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission ("SEC") on February 25, 2015, as amended by Amendment No. 1 to the Annual Report on Form 10-K/A, filed with the SEC on April 10, 2015 ("2014 Form 10-K").

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

Overview and history

We are an independent oil and natural gas company engaged in the exploration, exploitation, acquisition, development and production of onshore U.S. oil and natural gas properties with a focus on shale resource plays. Our principal operations are conducted in certain key U.S. oil and natural gas areas including Texas, Louisiana and the Appalachia region. Our primary strategy focuses on the exploitation and development of our shale resource plays and the pursuit of leasing and undeveloped acreage acquisition opportunities in Texas and Louisiana. We plan to carry out this strategy by executing on a strategic improvement plan that incorporates the following focus areas: (i) liability management; (ii) operational performance; (iii) capital deployment; (iv) risk management; (v) portfolio repositioning; and (vi) performance management. We believe this strategy will allow us to create long-term value for our shareholders.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. We attempt to offset the impact of this natural decline by implementing drilling and exploitation projects to identify and develop additional reserves and adding reserves through leasing and undeveloped acreage acquisition opportunities.

Recent developments

Second Lien Term Loans and note repurchases

On October 26, 2015, we closed a 12.5% senior secured second lien term loan in the aggregate principal amount $300.0 million (“Fairfax Term Loan”) and a 12.5% senior secured second lien term loan in the aggregate principal amount of $291.3 million (“Exchange Term Loan,” and together with the Fairfax Term Loan, “Second Lien Term Loans”). Each of the Second Lien Term Loans matures on October 26, 2020 and bears interest at a rate of 12.5% per annum, which is payable on the last day in each calendar quarter. The proceeds from the Fairfax Term Loan were used to reduce the outstanding indebtedness under the EXCO Resources Credit Agreement. Additionally, we used the proceeds from the Exchange Term Loan to repurchase $375.9 million of our 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and $200.7 million of our 8.5% senior unsecured notes due April 15, 2022 ("2022 Notes"). As a result of the repurchases, the aggregate principal amount of the outstanding 2018 Notes and 2022 Notes was reduced to $374.1 million and $299.3 million, respectively. See "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements for a more detailed discussion of these transactions and the description of the Second Lien Term Loans.

Proposed reverse share split

On July 30, 2015, we received a notice from the NYSE that the average closing price of our common shares over the prior 30 consecutive trading days was below $1.00 per share, and, as a result, the price per share of the common shares was below the minimum average closing price required to maintain listing on the NYSE. The notice stated that we have six months to regain compliance with the NYSE continued listing standards, or until January 30, 2016, or the NYSE would initiate procedures to suspend and delist the common shares. In order to regain compliance with the NYSE continued listing standards,

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

In September 2015, our Board of Directors authorized the calling of a Special Meeting of Shareholders to authorize the Board of Directors to effect a reverse share split at a ratio of up to 1-for-10 common shares. The decision to effect a reverse share split and the exact ratio of the reverse share split would be made by our Board of Directors in its sole discretion. If the Company effects the reverse share split, the common shares will be deemed to be in compliance with the NYSE listing standards if, promptly after the reverse share split, the price per common share exceeds $1.00 per share and remains above that level for at least the following 30 trading days. We have called a Special Meeting of Shareholders for November 16, 2015 for our shareholders to consider, among other things, a proposal to approve the reverse share split and proportionally reduce the total number of outstanding common shares that we are authorized to issue.

If our shareholders approve the reverse share split and our Board of Directors decide to effect the reverse share split, it will reduce the total number of our issued and outstanding common shares, including shares held by the Company as treasury shares, and the number of common shares each of our shareholders owns will be reduced in proportion to the reverse share split ratio. The proposed reverse share split will affect all shareholders uniformly and will not affect any shareholder's percentage ownership of the company. Our past and future earnings (losses) per share, and any dividends paid on our common shares, will be proportionately adjusted if the reverse share split is effected.

EXCO Resources Credit Agreement amendments

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

Appointment of Chief Executive Officer and Chief Operating Officer

On March 31, 2015, our Board of Directors appointed Harold L. Hickey to the position of President and Chief Executive Officer of EXCO. Mr. Hickey previously served as EXCO's President and Chief Operating Officer since February 2013 and Chief Operating Officer since October 2005.

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

Services and Investment Agreement

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


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


•	ESAS agreed to purchase additional common shares of EXCO through open market purchases such that ESAS will own common shares of EXCO with an aggregate cost basis of at least $23.5 million as of the first anniversary of the closing date, subject to certain extensions and exceptions;


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

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

•

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

For a more detailed discussion of this agreement, see "Note. 12. Services and Investment Agreement" 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, derivative financial instruments, business combinations, share-based compensation, goodwill, revenue recognition, asset retirement obligations and income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates were made. However, these estimates could change materially if different information or assumptions are used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in EXCO's 2014 Form 10-K.

Our results of operations

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

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	Three Months Ended September 30,					Quarter to quarter change			Nine Months Ended September 30,						Period to period change
(dollars in thousands, except per unit prices)	2015			2014		Quarter to quarter change			2015			2014			Period to period change
Production:
Oil (Mbbls)	635			537		98			1,733			1,709			24
Natural gas (Mmcf)	27,493			29,731		(2,238		)	84,257			94,203			(9,946		)
Total production (Mmcfe) (1)	31,303			32,953		(1,650		)	94,655			104,457			(9,802		)
Average daily production (Mmcfe)	340			358		(18		)	347			383			(36		)
Revenues before derivative financial instrument activities:
Oil	$	27,444		$	50,746	$	(23,302	)	$	79,872		$	159,131		$	(79,259	)
Natural gas	56,082			100,296		(44,214		)	183,716			373,349			(189,633		)
Total revenues	$	83,526		$	151,042	$	(67,516	)	$	263,588		$	532,480		$	(268,892	)
Oil and natural gas derivative financial instruments:
Gain (loss) on derivative financial instruments	$	37,348		$	42,844	$	(5,496	)	$	54,427		$	(14,896	)	$	69,323
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	43.22		$	94.50	$	(51.28	)	$	46.09		$	93.11		$	(47.02	)
Natural gas (per Mcf)	2.04			3.37		(1.33		)	2.18			3.96			(1.78		)
Natural gas equivalent (per Mcfe)	2.67			4.58		(1.91		)	2.78			5.10			(2.32		)
Costs and expenses:
Oil and natural gas operating costs	$	12,669		$	14,099	$	(1,430	)	$	41,745		$	48,713		$	(6,968	)
Production and ad valorem taxes	5,944			7,978		(2,034		)	16,408			22,951			(6,543		)
Gathering and transportation	23,743			25,822		(2,079		)	74,243			76,473			(2,230		)
Depletion	51,494			63,566		(12,072		)	174,509			197,102			(22,593		)
Depreciation and amortization	519			1,347		(828		)	1,651			4,339			(2,688		)
General and administrative (2)	13,393			14,059		(666		)	41,227			50,901			(9,674		)
Interest expense, net	27,761			23,974		3,787			80,822			70,106			10,716
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.40		$	0.43	$	(0.03	)	$	0.44		$	0.47		$	(0.03	)
Production and ad valorem taxes	0.19			0.24		(0.05		)	0.17			0.22			(0.05		)
Gathering and transportation	0.76			0.78		(0.02		)	0.78			0.73			0.05
Depletion	1.65			1.93		(0.28		)	1.84			1.89			(0.05		)
Depreciation and amortization	0.02			0.04		(0.02		)	0.02			0.04			(0.02		)
Net income (loss) (3)	$	(354,519	)	$	41,569	$	(396,088	)	$	(1,126,786	)	$	39,256		$	(1,166,042	)


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


(2)	Equity-based compensation expense included in general and administrative expense was $0.9 million and $1.1 million for the three months ended September 30, 2015 and 2014, respectively, and $4.0 million and $4.4 million for the nine months ended September 30, 2015 and 2014, respectively.


(3)	Net loss for the three and nine months ended September 30, 2015 included a $339.4 million and $1.0 billion impairment of oil and natural gas properties, respectively. See "Note 5. Oil and natural gas properties" in the Notes to Condensed Consolidated Financial Statements for further discussion.

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


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


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


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


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


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

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


•	significant changes in our capital structure as a result of the rights offering and related private placement of our common shares ("Rights Offering") in the first quarter of 2014 and debt financing transactions in 2014.

General

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 production;


•	the availability of imported oil and natural gas;


•	federal regulations generally prohibiting the export of U.S. crude oil;


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


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


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


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


•	the cost and availability of other competitive fuels;


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


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


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


•	the availability of refining capacity;


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


•	weather conditions and natural disasters;


•	foreign and domestic government relations; and


•	overall domestic and global economic conditions.

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

Oil and natural gas production, revenues and prices

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



	Three Months Ended September 30,
	2015					2014					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	18,161	$	39,131	$	2.15	19,934	$	71,491	$	3.59	(1,773	)	$	(32,360	)	$	(1.44	)
East Texas	4,763	12,516		2.63		2,311	8,383		3.63		2,452		4,133			(1.00		)
South Texas	4,064	25,450		6.26		3,241	45,829		14.14		823		(20,379		)	(7.88		)
Appalachia	4,315	6,429		1.49		5,148	13,279		2.58		(833	)	(6,850		)	(1.09		)
Other	—	—		—		2,319	12,060		5.20		(2,319	)	(12,060		)	(5.20		)
Total	31,303	$	83,526	$	2.67	32,953	$	151,042	$	4.58	(1,650	)	$	(67,516	)	$	(1.91	)

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	Nine Months Ended September 30,
	2015					2014					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	57,851	$	133,192	$	2.30	64,600	$	268,100	$	4.15	(6,749	)	$	(134,908	)	$	(1.85	)
East Texas	12,465	33,603		2.70		6,243	26,252		4.21		6,222		7,351			(1.51		)
South Texas	11,183	75,082		6.71		10,320	141,537		13.71		863		(66,455		)	(7.00		)
Appalachia	13,154	21,707		1.65		16,273	54,952		3.38		(3,119	)	(33,245		)	(1.73		)
Other	2	4		2.00		7,021	41,639		5.93		(7,019	)	(41,635		)	(3.93		)
Total	94,655	$	263,588	$	2.78	104,457	$	532,480	$	5.10	(9,802	)	$	(268,892	)	$	(2.32	)

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

•

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


•	increased production of 2.5 Bcfe and 6.2 Bcfe for the three and nine months ended September 30, 2015, respectively, in the East Texas region due to additional development as we resumed our drilling program in this region during 2014 and this region has been the primary focus of our 2015 development program.


•	increased production in the South Texas region of 0.8 Bcfe and 0.9 Bcfe for the three and nine months ended September 30, 2015, respectively, due to additional volumes from recent wells turned-to-sales in the Eagle Ford shale and Buda formation.

•

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


•	decreased production in the Other region primarily due to the sale of our interest in Compass during the fourth quarter of 2014.

Oil and natural gas revenues for the three months ended September 30, 2015 decreased by $67.5 million, or 45%, as compared with the same period in 2014. The decrease in revenues was primarily the result of a decrease in oil and natural gas prices as well as decreased production. Our average natural gas sales price decreased 39% to $2.04 per Mcf for the three months ended September 30, 2015 from $3.37 per Mcf for the three months ended September 30, 2014, primarily due to lower market prices. Our average sales price of oil per Bbl decreased 54% to $43.22 per Bbl for the three months ended September 30, 2015 from $94.50 per Bbl for the three months ended September 30, 2014, primarily due to lower market prices. The impact of lower market prices was partially offset by improved differentials in the South Texas region as a result a renegotiated sales contract which resulted in a higher realized price for the related oil production.

Oil and natural gas revenues for the nine months ended September 30, 2015 decreased by $268.9 million, or 50%, as compared with the same period in 2014. The decrease in revenues was primarily the result of a decrease in oil and natural gas prices as well as decreased production. Our average natural gas sales price decreased 45% to $2.18 per Mcf for the nine months ended September 30, 2015 from $3.96 per Mcf for the nine months ended September 30, 2014, primarily due to lower market prices. The realized prices for natural gas during the nine months ended September 30, 2015 and 2014 were negatively impacted by wide differentials in Appalachia as a result of an oversupply of natural gas in the Northeast region. Our average sales price of oil per Bbl decreased 50% to $46.09 per Bbl for the nine months ended September 30, 2015 from $93.11 per Bbl for the nine months ended September 30, 2014, primarily due to lower market prices.

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Oil and natural gas operating costs

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



	Three Months Ended September 30,
	2015						2014						Quarter to quarter change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
North Louisiana	$	3,386	$	252	$	3,638	$	3,619	$	856	$	4,475	$	(233	)	$	(604	)	$	(837	)
East Texas	967		238		1,205		758		112		870		209			126			335
South Texas	3,814		944		4,758		825		49		874		2,989			895			3,884
Appalachia	2,745		315		3,060		3,698		52		3,750		(953		)	263			(690		)
Other	8		—		8		3,637		493		4,130		(3,629		)	(493		)	(4,122		)
Total	$	10,920	$	1,749	$	12,669	$	12,537	$	1,562	$	14,099	$	(1,617	)	$	187		$	(1,430	)

	Three Months Ended September 30,
	2015						2014						Quarter to quarter change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
North Louisiana	$	0.19	$	0.01	$	0.20	$	0.18	$	0.04	$	0.22	$	0.01		$	(0.03	)	$	(0.02	)
East Texas	0.20		0.05		0.25		0.33		0.05		0.38		(0.13		)	—			(0.13		)
South Texas	0.94		0.23		1.17		0.25		0.02		0.27		0.69			0.21			0.90
Appalachia	0.64		0.07		0.71		0.72		0.01		0.73		(0.08		)	0.06			(0.02		)
Other	—		—		—		1.57		0.21		1.78		(1.57		)	(0.21		)	(1.78		)
Total	$	0.35	$	0.05	$	0.40	$	0.38	$	0.05	$	0.43	$	(0.03	)	$	—		$	(0.03	)



	Nine Months Ended September 30,
	2015						2014						Period to period change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
North Louisiana	$	9,814	$	2,637	$	12,451	$	11,108	$	3,186	$	14,294	$	(1,294	)	$	(549	)	$	(1,843	)
East Texas	2,983		1,027		4,010		2,231		223		2,454		752			804			1,556
South Texas	14,647		1,756		16,403		9,274		347		9,621		5,373			1,409			6,782
Appalachia	8,403		440		8,843		10,782		58		10,840		(2,379		)	382			(1,997		)
Other	38		—		38		9,928		1,576		11,504		(9,890		)	(1,576		)	(11,466		)
Total	$	35,885	$	5,860	$	41,745	$	43,323	$	5,390	$	48,713	$	(7,438	)	$	470		$	(6,968	)

	Nine Months Ended September 30,
	2015						2014						Period to period change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
North Louisiana	$	0.17	$	0.05	$	0.22	$	0.17	$	0.05	$	0.22	$	—		$	—		$	—
East Texas	0.24		0.08		0.32		0.36		0.04		0.40		(0.12		)	0.04			(0.08		)
South Texas	1.31		0.16		1.47		0.90		0.03		0.93		0.41			0.13			0.54
Appalachia	0.64		0.03		0.67		0.66		—		0.66		(0.02		)	0.03			0.01
Other	19.00		—		19.00		1.41		0.22		1.63		17.59			(0.22		)	17.37
Total	$	0.38	$	0.06	$	0.44	$	0.41	$	0.06	$	0.47	$	(0.03	)	$	—		$	(0.03	)

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Oil and natural gas operating costs for the three and nine months ended September 30, 2015 decreased by $1.4 million, or 10%, and $7.0 million, or 14%, respectively, as compared with the same periods in 2014. The decrease was primarily due to the sale of our interest in Compass in the fourth quarter of 2014 and cost reduction efforts in the North Louisiana and Appalachia regions. These decreases were partially offset by higher oil and natural gas operating costs in the East Texas and South Texas regions as a result of additional producing wells compared to prior periods. The decrease in oil and natural operating costs per Mcfe was primarily due to the sale of our interest in Compass which had a higher average cost per Mcfe compared to the average for the rest of our properties.

Gathering and transportation

Gathering and transportation expenses for the three and nine months ended September 30, 2015 decreased by $2.1 million, or 8%, and $2.2 million, or 3%, respectively, as compared with the same periods in 2014. The decrease was primarily due to reduced rates on a renegotiated firm transportation contract in the North Louisiana region, sale of our interest in Compass and decreased production in Appalachia. These decreases were partially offset by additional expenses incurred as a result of a shortfall under a minimum volume commitment for gathering services in the East Texas and North Louisiana regions. Gathering and transportation expenses were $0.76 per Mcfe for the three months ended September 30, 2015 as compared to $0.78 per Mcfe for the same period in 2014. The decrease was primarily due to increased production in the East Texas region. Gathering and transportation expenses were $0.78 per Mcfe for the nine months ended September 30, 2015 as compared to $0.73 per Mcfe for the same period in 2014. The increase was primarily due to lower volumes in relation to fixed costs under firm transportation contracts in the East Texas and North Louisiana regions.

Production and ad valorem taxes

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



	Three Months Ended September 30,
	2015							2014
(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	$	2,431		6.2	%	$	0.13	$	2,455	3.4	%	$	0.12
East Texas	522			4.2	%	0.11		207		2.5	%	0.09
South Texas	2,592			10.2	%	0.64		3,667		8.0	%	1.13
Appalachia	399			6.2	%	0.09		524		3.9	%	0.10
Other	—			—	%	—		1,125		9.3	%	0.49
Total	$	5,944		7.1	%	$	0.19	$	7,978	5.3	%	$	0.24

	Nine Months Ended September 30,
	2015							2014
(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	$	7,393		5.6	%	$	0.13	$	6,746	2.5	%	$	0.10
East Texas	822			2.4	%	0.07		629		2.4	%	0.10
South Texas	7,299			9.7	%	0.65		10,128		7.2	%	0.98
Appalachia	902			4.2	%	0.07		1,728		3.1	%	0.11
Other	(8		)	N/M		N/M		3,720		8.9	%	0.53
Total	$	16,408		6.2	%	$	0.17	$	22,951	4.3	%	$	0.22

Production and ad valorem taxes for the three months ended September 30, 2015 decreased by $2.0 million, or 25%, as compared with the same period in 2014. Production and ad valorem taxes for the nine months ended September 30, 2015 decreased by $6.5 million, or 29%, as compared with the same period in 2014. The decrease was primarily due to lower production volumes and lower commodity prices. The lower commodity prices primarily impacted properties located in Texas because production taxes are based on a fixed percentage of gross value of production sold. The decrease in the rate per Mcfe was primarily due to the sale of our interest in Compass in the fourth quarter of 2014 which had higher average production and

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

In our North Louisiana region, we currently receive severance tax holidays on certain horizontal wells which reduce the effective rate of these taxes. Our horizontal wells in the state of Louisiana are eligible for an exemption from severance taxes for the earlier of two years from the date of first production or until payout of qualified costs. In July 2014, the state of Louisiana increased its severance tax rate for wells that do not receive exemptions from $0.118 per Mcf to $0.163 per Mcf. In July 2015, the effective severance tax rate decreased to $0.158 per Mcf.

Depletion, depreciation and amortization

Depletion expense for the three months ended September 30, 2015 decreased by $12.1 million, or 19%, as compared with the same period in 2014 primarily due to a decrease in production and the depletion rate. On a per Mcfe basis, the depletion rate for the three months ended September 30, 2015 was $1.65 per Mcfe, compared with $1.93 per Mcfe in the same period in 2014. Depletion expense for the nine months ended September 30, 2015 decreased by $22.6 million, or 11%, as compared with the same period in 2014 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, 2015 was $1.84 per Mcfe, compared with $1.89 per Mcfe in the same period in 2014. The decrease in the depletion rate was primarily due to the impairments of our oil and natural gas properties during 2015, which lowered our depletable base.

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

Impairment of oil and natural gas properties

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

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

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General and administrative

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



	Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands, except per unit rate)	2015			2014			Quarter to quarter change			2015			2014			Period to period change
General and administrative expenses:
Gross general and administrative expenses	$	22,935		$	28,031		$	(5,096	)	$	71,920		$	92,908		$	(20,988	)
Technical services and service agreement charges	(3,541		)	(6,365		)	2,824			(12,314		)	(19,148		)	6,834
Operator overhead reimbursements	(3,328		)	(3,628		)	300			(9,872		)	(10,461		)	589
Capitalized salaries and equity-based compensation	(2,673		)	(3,979		)	1,306			(8,507		)	(12,398		)	3,891
General and administrative expenses	$	13,393		$	14,059		$	(666	)	$	41,227		$	50,901		$	(9,674	)

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


•	decreased personnel costs of $4.0 million and $12.8 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in the prior year. The decrease is primarily the result of reductions in our workforce that occurred during the second quarter of 2014 and the first quarter of 2015;


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


•	decreased technical services and service agreement recoveries of $2.8 million and $6.8 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in the prior year. These decreases were primarily a result of reduced headcount and lower recoveries in connection with the service agreement with Compass that terminated in April 2015; and


•	decreased capitalized salaries and equity-based compensation expenses of $1.3 million and $3.9 million for the three and nine months ended September 30, 2015, respectively, compared to the same periods in the prior year. These decreases were primarily as a result of a reduction in employee headcount.

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

Other operating items

Other operating items was a net gain of $0.2 million for the three months ended September 30, 2015 primarily due to income from surface acreage that we own in the South Texas region and a net loss of $1.1 million for the nine months ended September 30, 2015 primarily due to various legal expenses and other assessments. Other operating items was a net loss of $0.7 million and $6.4 million for the three and nine months ended September 30, 2014, respectively. The net losses for both periods primarily consisted of legal expenses.

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Interest expense, net

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



	Three Months Ended September 30,									Nine Months Ended September 30,
(in thousands)	2015			2014			Quarter to quarter change			2015			2014			Period to period change
Interest expense, net:
2018 Notes	$	14,426		$	14,399		$	27		$	43,259		$	43,179		$	80
2022 Notes	10,625			10,625			—			31,875			19,479			12,396
EXCO Resources Credit Agreement	2,024			1,607			417			5,672			14,628			(8,956		)
Compass Production Partners Credit Agreement	—			610			(610		)	—			1,820			(1,820		)
Amortization of deferred financing costs	3,745			1,854			1,891			10,012			6,117			3,895
Capitalized interest	(3,094		)	(5,155		)	2,061			(10,121		)	(15,410		)	5,289
Other	35			34			1			125			293			(168		)
Total interest expense, net	$	27,761		$	23,974		$	3,787		$	80,822		$	70,106		$	10,716

Interest expense, net for the three months ended September 30, 2015 increased $3.8 million from the same period in 2014. The increase in interest expense was primarily due to the acceleration of deferred financing costs of $2.0 million associated with the reduction in our borrowing base under the EXCO Resources Credit Agreement in July 2015 and a reduction in capitalized interest related to lower balances of unproved oil and natural gas properties.

Interest expense, net for the nine months ended September 30, 2015 increased $10.7 million from the same period in 2014. The increase in interest expense was primarily due to higher average interest rates as a result of the issuance of the 2022 Notes, the acceleration of deferred financing costs associated with the reduction in our borrowing base under the EXCO Resources Credit Agreement in February 2015 and July 2015 and a reduction in capitalized interest related to lower balances of unproved oil and natural gas properties. This was partially offset by the acceleration of the unamortized discount on the term loan under the EXCO Resources Credit Agreement upon repayment in April 2014 and reduction in interest expense related to the Compass Production Partners Credit Agreement as a result of the sale of our remaining interest in Compass.

The issuance of the Second Lien Term Loans in October 2015 and the use of proceeds reduced our total outstanding indebtedness by $285.3 million; however, these transactions will increase the average interest rate on our outstanding indebtedness. As a result of these transactions, we expect our annual interest expense to increase by approximately $21.0 million, excluding the impact of capitalized interest and amortization of deferred financing costs and discount on debt issuance. The repurchase of the 2018 Notes and 2022 Notes at a discount to the par value that occurred in the fourth quarter of 2015 is expected to result in a gain on the extinguishment of debt of approximately $270.0 million to $280.0 million.

Derivative financial instruments

Our oil and natural gas derivative financial instruments resulted in a net gain of $37.3 million and $42.8 million for the three months ended September 30, 2015 and 2014, respectively. Our oil and natural gas derivative financial instruments resulted in a net gain of $54.4 million and a net loss of $14.9 million for the nine months ended September 30, 2015 and 2014, respectively. Based on the nature of our derivative contracts, increases in the related commodity price typically result in a decrease to the value of our derivatives contracts. The significant fluctuations demonstrate the high volatility in oil and natural gas prices between each of the periods. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

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



	Three Months Ended September 30,								Nine Months Ended September 30,
Average realized pricing:	2015		2014			Quarter to quarter change			2015		2014			Period to period change
Natural gas (per Mcf):
Net price, excluding derivatives	$	2.04	$	3.37		$	(1.33	)	$	2.18	$	3.96		$	(1.78	)
Cash receipts (payments) on derivatives	0.70		0.11			0.59			0.67		(0.28		)	0.95
Net price, including derivatives	$	2.74	$	3.48		$	(0.74	)	$	2.85	$	3.68		$	(0.83	)
Oil (per Bbl):
Net price, excluding derivatives	$	43.22	$	94.50		$	(51.28	)	$	46.09	$	93.11		$	(47.02	)
Cash receipts (payments) on derivatives	19.97		(1.96		)	21.93			18.95		(3.67		)	22.62
Net price, including derivatives	$	63.19	$	92.54		$	(29.35	)	$	65.04	$	89.44		$	(24.40	)
Natural gas equivalent (per Mcfe):
Net price, excluding derivatives	$	2.67	$	4.58		$	(1.91	)	$	2.78	$	5.10		$	(2.32	)
Cash receipts (payments) on derivatives	1.02		0.07			0.95			0.94		(0.31		)	1.25
Net price, including derivatives	$	3.69	$	4.65		$	(0.96	)	$	3.72	$	4.79		$	(1.07	)

Our total cash receipts for the three months ended September 30, 2015 were $31.9 million, or $1.02 per Mcfe, compared to cash receipts of $2.3 million, or $0.07 per Mcfe, for the three months ended September 30, 2014. Our total cash receipts for the nine months ended September 30, 2015 were $89.0 million, or $0.94 per Mcfe, compared to cash payments $32.2 million, or $0.31 per Mcfe for the nine months ended September 30, 2014. The differences between the cash receipts during 2015 and cash payments during 2014 were primarily due to the significant decline in oil and natural gas prices. As noted above, the significant fluctuations between settlements on our derivative financial instruments demonstrate the volatility in commodity prices. We will continue to evaluate plans to enter into additional derivative contracts based on market conditions.

Income taxes

Our effective income tax rate for the three and nine months ended September 30, 2015 and 2014 was zero, primarily due to prior losses arising from impairments of oil and natural gas properties which created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our accumulated valuation allowance as of September 30, 2015 was approximately $1.3 billion and can be used to offset future taxable income. We will continue to recognize deferred tax valuation allowances until the realization of deferred benefits becomes more likely than not. The effective income tax rates, excluding the impact of the valuation allowances, would have been 38.5% and 38.7% for the three and nine months ended September 30, 2015, respectively, and 32.1% and 42.9% for the three and nine months ended September 30, 2014, respectively. The effective tax rates, excluding the impact of the valuation allowance, differ from the statutory tax rates primarily due to permanent differences between the amounts recorded for financial reporting purposes and the amounts used for income tax purposes.

Our liquidity, capital resources and capital commitments

Overview

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


•	the level of planned drilling activities;


•	the results of our ongoing drilling programs;


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


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


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

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


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


•	our ability to meet minimum volume commitments under firm transportation agreements and other fixed commitments;


•	potential acquisitions and/or dispositions of oil and natural gas properties or other assets, including our ability to obtain financing in order to fund the acquisition of properties under a participation agreement with a joint venture partner in the Eagle Ford shale;


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


•	our ability to pay interest on our outstanding indebtedness, including the expected increase in our annual interest expense as a result of the issuance of the Second Lien Term Loans;


•	reductions to our borrowing base; and


•	our ability to maintain compliance with debt covenants.

Recent events affecting liquidity

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

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

Our 2015 capital budget is expected to exceed our cash flows from operations and the deficit will be funded with borrowings under the EXCO Resources Credit Agreement. We continue to evaluate and implement further cost reduction initiatives to mitigate the impact of low commodity prices on our cash flows and liquidity. The initiatives implemented during 2015 have included a reduction in our workforce, reduced operating and capital expenditures through negotiations with key vendors and restructuring of commercial contracts including sales and firm transportation agreements. We are currently evaluating transactions that could further enhance our liquidity and capital structure including the issuance of additional indebtedness, restructure or repurchase of existing indebtedness, cost reductions and divestitures of assets. The Company currently has approximately $109 million of additional second lien capacity under the Exchange Term Loan and approximately $125 million of third lien capacity. The Company is evaluating further opportunities to exchange outstanding unsecured notes for second or third lien term loans. In addition, we have taken preliminary actions to assess the potential market and valuation if we were to divest certain of our assets. There is no assurance any such transactions will occur.

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



(in thousands)	September 30, 2015		Pro Forma
EXCO Resources Credit Agreement	$	299,992	$	—
Second Lien Term Loans (1)	—		591,330
2018 Notes (2)	750,000		374,058
2022 Notes	500,000		299,269
Total debt	$	1,549,992	$	1,264,657
Net debt	$	1,508,027	$	1,237,684
Borrowing base	$	600,000	$	375,000
Unused borrowing base (3)	$	293,410	$	368,402
Cash (4)	$	41,965	$	26,973
Unused borrowing base plus cash	$	335,375	$	395,375


(1)	The proceeds from the Second Lien Term Loans were utilized to reduce indebtedness under the EXCO Resources Credit Agreement and repurchase $375.9 million in aggregate principal amount of the 2018 Notes and $200.7 million in aggregate principal amount of the 2022 Notes.


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


(3)	Net of $6.6 million in letters of credit as of September 30, 2015. In connection with the issuance of the Second Lien Term Loans in October 2015, the borrowing base under the EXCO Resources Credit Agreement was reduced to $375.0 million.


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

Credit agreements and long-term debt

As of September 30, 2015, our consolidated debt consisted of the EXCO Resources Credit Agreement, the 2018 Notes and the 2022 Notes (see "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements for a further description of each agreement).

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


•	our consolidated current ratio of 2.1 to 1.0 exceeded the minimum of at least 1.0 to 1.0 as of the end of any fiscal quarter;


•	our Interest Coverage Ratio of 2.6 to 1.0 exceeded the minimum of at least 2.0 to 1.0 as of the end of any fiscal quarter; and


•	our Secured Indebtedness Ratio of 1.1 to 1.0 did not exceed the maximum of 2.5 to 1.0 as of the end of any fiscal quarter.

The issuance of the Second Lien Term Loans triggered a modification of certain covenants in the EXCO Resources Credit Agreement. The Interest Coverage Ratio was modified to require that we maintain a ratio of at least 1.25 to 1.00 as of the end of any fiscal quarter and the leverage ratio requirement was eliminated. The Second Lien Term Loans and the indentures governing the 2018 Notes and 2022 Notes contain incurrence covenants which restrict our ability to incur additional indebtedness, incur liens to secure any such additional indebtedness or pledge assets. These incurrence covenants include limitations on our indebtedness that are based, in part, on the greater of a monetary threshold or the value of our assets. Therefore, our ability to incur additional indebtedness could be limited to the extent that low oil and natural gas prices negatively impact the value of our assets. See further details on the limitations on our ability to incur additional indebtedness as described in "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements.

There are certain risks arising from volatility in oil and/or natural gas prices that could restrict our liquidity or impact our ability to meet debt covenants in future periods. Furthermore, our liquidity and ability to meet debt covenants in future periods is partially dependent on our ability to offset natural production declines through the development of our oil and natural gas properties. If we are not able to generate sufficient returns from the future development of our oil and natural gas properties, we may not undertake these projects and be able to adequately offset our natural production declines. The profitability of our future development projects is dependent on commodity prices, estimates of reserves, drilling and completion costs, operating

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

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

In the event that our liquidity is not sufficient to fund our operating activities and development program or we are not able to meet our debt covenants in future periods, we may attempt to refinance all or part of our existing debt, sell assets, incur additional indebtedness or raise equity. These alternatives may not be available on terms acceptable to us, which could adversely affect our business, financial condition and results of operations. Further, failing to comply with the financial and other restrictive covenants in the EXCO Resources Credit Agreement, Second Lien Term Loans, 2018 Notes or 2022 Notes could result in an event of default, which could adversely affect our business, financial condition and results of operations. Also, we may be required to surrender certain assets pursuant to the security provisions of the EXCO Resources Credit Agreement and Second Lien Term Loans if we are not able to meet our debt covenants in future periods. See "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements for a description of our covenants under the EXCO Resources Credit Agreement, Second Lien Term Loans, 2018 Notes and 2022 Notes.

Capital expenditures

For the nine months ended September 30, 2015, our capital expenditures totaled $242.2 million, of which $202.3 million was related to drilling and development activities. Our development program during the nine months ended September 30, 2015 included three operated drilling rigs focused primarily on the Haynesville and Bossier shales in the Shelby area of East Texas. Our development activities in North Louisiana during 2015 included limited drilling as well as completion activities in Caddo and DeSoto Parishes, Louisiana. Our development program in the South Texas region included an average of one operated drilling rig focused on the Eagle Ford shale and the Buda formation. Our capital expenditures in the South Texas region also included the leasing of acreage in Zavala County, Texas. As a result of the decline in oil prices, we suspended our drilling in the South Texas region for the remainder of 2015. We drilled an appraisal well in the Marcellus shale in Northeast Pennsylvania which is expected to be turned-to-sales during the first quarter of 2016. In response to the downturn in commodity prices, we have negotiated reductions in service costs with certain key vendors utilized in our drilling and completion activities and continue to pursue further reductions.

The following table presents our capital expenditures for the nine months ended September 30, 2015 and our forecasted capital expenditures for the remainder of 2015. Our capital program allocates a higher proportionate share of our expenditures towards the beginning of the year primarily as a result of completion activities related to wells that were in various stages of the development process at the end of 2014.



	Nine Months Ended		October - December Forecast		Full Year Forecast
(in thousands)	September 30, 2015		2015		2015
Capital expenditures:
Development capital expenditures	$	202,277	$	37,723	$	240,000
Field operations, gathering and water pipelines	5,487		9,513		15,000
Lease purchases and seismic	10,859		7,141		18,000
Corporate and other	23,585		3,415		27,000
Total	$	242,208	$	57,792	$	300,000

Capital commitments

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

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

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

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

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

Historical sources and uses of funds

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

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



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

Operating activities

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

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For the nine months ended September 30, 2015, our net cash provided by operating activities was $126.9 million as compared to $358.4 million for the nine months ended September 30, 2014. The decrease was primarily attributable to lower revenues from lower production and decreased oil and natural gas prices. In addition, the decrease was due to changes in accounts payable resulting from lower collections from advance billings to other working interest owners in the Eagle Ford shale as well as lower collections of revenues payable to other owners. The decrease was partially offset by cash receipts of $89.0 million on derivative contracts for the nine months ended September 30, 2015 compared to cash payments of $32.2 million for the same period in the prior year.

Investing activities

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

For the nine months ended September 30, 2015, our net cash used in investing activities was $255.9 million primarily due to our drilling and completion activities in the East Texas, North Louisiana and South Texas regions. The cash used in investing activities for the nine months ended September 30, 2015 included a significant amount of expenditures related to the wells drilled in 2014. For the nine months ended September 30, 2014, our net cash used in investing activities was $237.0 million primarily due to drilling and development activities in the East Texas, North Louisiana and South Texas regions. This was partially offset by approximately $68.2 million of proceeds received from the sale of our interest in certain non-operated assets in the Permian Basin.

Financing activities

For the nine months ended September 30, 2015, our net cash provided by financing activities was $103.2 million primarily due to $97.5 million in borrowings under the EXCO Resources Credit Agreement and $9.8 million in net proceeds from the issuance of common shares to ESAS. For the nine months ended September 30, 2014, our net cash used in financing activities was $123.9 million primarily due to $839.9 million in net payments of the outstanding borrowings under the EXCO Resources Credit Agreement, $40.6 million of dividend payments and $10.1 million of deferred financing costs primarily related to issuance of the 2022 Notes. This was partially offset by $500.0 million of gross proceeds received from issuance of the 2022 Notes and approximately $272.9 million of gross proceeds received from the Rights Offering.

Derivative financial instruments

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

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



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

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

See further details on our derivative financial instruments in "Note 7. Derivative financial instruments" and "Note 8. Fair value measurements" in the Notes to our Condensed Consolidated Financial Statements.

Off-balance sheet arrangements

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

Contractual obligations and commercial commitments

On October 26, 2015, we closed the Second Lien Term Loans and utilized the proceeds to repay indebtedness under the EXCO Resources Credit Agreement and repurchase a portion of the 2018 Notes and the 2022 Notes. See "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements for further discussion. There have been no other material changes outside the ordinary course of business to our contractual obligations and commercial commitments since December 31, 2014.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity price risk

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

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

Our use of derivative financial instruments could have the effect of reducing our revenues and the value of our securities. For the nine months ended September 30, 2015, a $1.00 increase in the average commodity price per Mcfe would have resulted in an increase in cash settlement payments (or a decrease in settlements received) of approximately $41.9 million for our oil and natural gas swap contracts. The ultimate settlement amount of our outstanding derivative financial instrument contracts is dependent on future commodity prices. We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place.

Interest rate risk

At September 30, 2015, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement. The interest rates per annum on the 2018 Notes, 2022 Notes and Second Lien Term Loans are fixed at 7.5%, 8.5% and 12.5%, respectively. Interest is payable on borrowings under the EXCO Resources Credit Agreement based on a floating rate as more fully described in "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements. At September 30, 2015, we had approximately $300.0 million in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% increase in interest rates (100 bps) based on the variable borrowings as of September 30, 2015 would result in an increase in our interest expense of approximately $3.0 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

Item 4. Controls and Procedures

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

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

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PART II—OTHER INFORMATION


Item 1.	Legal Proceedings

In the ordinary course of business, we are periodically a party to various litigation matters. We do not believe that any resulting liability from existing legal proceedings, individually or in the aggregate, will have a material adverse effect on our results of operations or financial condition.


Item 1A.	Risk Factors

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

If we fail to comply with the continued listing standards of the NYSE, it may result in a delisting of our common shares from the NYSE.

Our common shares are currently and have been listed for trading on the NYSE, and the continued listing of our common shares on the NYSE is subject to our compliance with a number of listing standards. To maintain compliance with these continued listing standards, the Company is required to maintain an average closing price of $1.00 or more over a consecutive 30 trading-day period. On July 30, 2015, we received a notice from the NYSE that the average closing price of our common shares over the prior 30 consecutive trading days was below $1.00 per share, and, as a result, the price per share of the common shares was below the minimum average closing price required to maintain listing on the NYSE. The notice stated that we had six months to regain compliance with the NYSE continued listing standards, or until January 30, 2016, or the NYSE would initiate procedures to suspend and delist the common shares.

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

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

We have recently experienced losses as a result of the recent decline in oil and natural gas prices, and, as of September 30, 2015, we had negative shareholders’ equity of $600 million, which means that our total liabilities exceeded our total assets. The continuing existence of negative shareholders’ equity may limit our ability to obtain future debt or equity financing or to pay future dividends or other distributions. If we are unable to obtain financing in the future, it could have a negative effect on our operations and our liquidity.

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

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

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

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

As a result, there may be an actual or apparent conflict of interest between Mr. Mitchell’s duties to our company and Mr. Mitchell’s duties to Hamblin Watsa, including, among other things, with respect to the fairness of the terms of the Fairfax Term Loan to EXCO. In accordance with the charter of the audit committee of our Board of Directors, our audit committee reviewed and pre-approved the terms of the Fairfax Term Loan as a related party transaction, and our Board of Directors determined that the terms of the Fairfax Term Loan were no less favorable to EXCO or our subsidiaries than those that could be obtained in arm’s length dealings with non-affiliates, and, in the good faith judgment of our Board of Directors, no comparable transaction was available with which to compare the Fairfax Term Loan and the Fairfax Term Loan was fair, from a financial point of view, to EXCO.

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


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

Issuer repurchases of common shares

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



Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in millions) (2)
July 1, 2015 - July 31, 2015	16,621	$	1.03	—	$	192.5
August 1, 2015 - August 31, 2015	—	—		—	192.5
September 1, 2015 - September 30, 2015	—	—		—	192.5
Total	16,621	$	1.03	—


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


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


Item 6.	Exhibits

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

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SIGNATURES

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



		EXCO RESOURCES, INC.
		(Registrant)

Date:	October 28, 2015	/s/ Harold L. Hickey
		Harold L. Hickey
		Chief Executive Officer and President

		/s/ Richard A. Burnett
		Richard A. Burnett
		Vice President, Chief Financial Officer
		and Chief Accounting Officer

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INDEX TO EXHIBITS

Exhibit


Number	Description of Exhibits


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


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


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

2.4

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


3.1	Amended and Restated Certificate of Formation of EXCO Resources, Inc., 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.


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, 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, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.


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


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


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


4.6	Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Registration Statement on Form S-3 (File No. 333-192898), filed on December 17, 2013 and incorporated by reference herein.

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


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


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

4.10

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

4.11

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


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


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


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


10.4	Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*


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


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


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


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

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10.9	Fourth Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 16, 2011 and filed on March 22, 2011 and incorporated by reference herein.*


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


10.11	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 for 2009 filed on February 24, 2010 and incorporated by reference herein.*


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


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


10.14	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, dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.*


10.15	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, dated October 6, 2011 and filed on October 7, 2011 and incorporated by reference herein.*


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


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


10.18	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, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.


10.19	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 for 2010 filed February 24, 2011 and incorporated by reference herein.


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


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


10.22	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 for 2010 filed February 24, 2011 and incorporated by reference herein.


10.23	Amendment to Joint Development Agreement, dated October 14, 2014, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production

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Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2014 filed on February 25, 2015 and incorporated by reference herein.


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


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


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

10.27

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


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


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


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


10.31	Guaranty, dated June 1, 2010, by BG North America, LLC in favor of (i) EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC and EXCO Resources (PA), LLC; and (ii) EXCO Resources (PA), LLC and EXCO Holding (PA), Inc, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.


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


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


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


10.35	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 Form 8-K, dated as of August 28, 2013 and filed on September 4, 2013 and incorporated by reference herein.

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

10.37

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

10.38

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


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

10.40

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

10.41

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

10.42

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.


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


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

10.45

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


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


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


10.48	Participation Agreement, dated July 31, 2013, among Admiral A Holding L.P., Admiral B Holding L.P. and EXCO Operating Company, LP, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2013 filed on August 7, 2013 and incorporated by reference herein.

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10.49	Amendment No. 1 to Participation Agreement, dated April 17, 2014, among EXCO Operating Company, LP, Admiral A Holding L.P. and Admiral B Holding L.P., 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.


10.50	Amendment No. 2 to Participation Agreement, dated June 1, 2015, among EXCO Operating Company, LP, Admiral A Holding L.P., TE Admiral A Holding L.P. and Colt A Holding L.P., filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended June 30, 2015 filed on July 27, 2015 and incorporated by reference herein.


10.51	Form of Director Indemnification Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 10, 2010 and filed on November 12, 2010 and incorporated by reference herein.


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

10.53

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


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


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


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


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


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


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


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


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


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

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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.


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


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


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


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


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


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


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


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


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

10.73

Registration Rights Waiver, dated as of April 13, 2015, by and among EXCO Resources, Inc. and Advent Capital (No. 3) Limited, Clearwater Insurance Company, Clearwater Select Insurance Company, Fairfax Financial Holdings Master Trust Fund, Northbridge General Insurance Company, Odyssey Reinsurance Company, RiverStone Insurance Limited, Zenith Insurance Company and Hamblin Watsa Investment Counsel, Ltd., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 21, 2015 and filed on April 27, 2015 and incorporated by reference herein.

10.74

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

10.75

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


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

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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.

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