Exco Resources (EXCO) 10-Q 2014 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

______________________________

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

For the quarterly period ended June 30, 2014

OR

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

For the transition period from             to            

Commission File Number 001-32743

______________________________ 

EXCO RESOURCES, INC.

(Exact name of registrant as specified in its charter)

______________________________

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

(214) 368-2084

(Registrant’s telephone number, including area code)

______________________________

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

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

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

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

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

The number of shares of common stock, par value $0.001 per share, outstanding as of July 24, 2014 was 272,735,202.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at June 30, 2014 and December 31, 2013	2
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	4
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	5
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2014 and 2013	6
	Notes to Condensed Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	45
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 6.	Exhibits	45
	Signatures	46

1

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	June 30, 2014			December 31, 2013
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	45,878		$	50,483
Restricted cash	15,221			20,570
Accounts receivable, net:
Oil and natural gas	127,193			128,352
Joint interest	49,913			70,759
Other	6,011			18,022
Derivative financial instruments	2,330			8,226
Inventory and other	12,047			9,442
Total current assets	258,593			305,854
Equity investments	56,514			57,562
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	369,000			425,307
Proved developed and undeveloped oil and natural gas properties	3,736,988			3,554,210
Accumulated depletion	(2,316,974		)	(2,183,464		)
Oil and natural gas properties, net	1,789,014			1,796,053
Gathering assets	36,699			33,473
Accumulated depreciation and amortization	(11,184		)	(10,338		)
Gathering assets, net	25,515			23,135
Office, field and other equipment, net	25,873			27,204
Deferred financing costs, net	35,011			28,807
Derivative financial instruments	2,773			6,829
Goodwill	163,155			163,155
Other assets	30			29
Total assets	$	2,356,478		$	2,408,628

See accompanying notes.

2

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share and share data)	June 30, 2014			December 31, 2013
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	106,787		$	109,217
Revenues and royalties payable	184,025			154,862
Drilling advances	51,589			22,971
Accrued interest payable	26,284			18,144
Current portion of asset retirement obligations	191			191
Income taxes payable	—			—
Derivative financial instruments	29,451			11,919
Current maturities of long-term debt	—			31,866
Total current liabilities	398,327			349,170
Long-term debt	1,511,647			1,858,912
Deferred income taxes	—			—
Derivative financial instruments	5,454			9,671
Asset retirement obligations and other long-term liabilities	44,468			42,970
Commitments and contingencies	—			—
Shareholders’ equity:
Common stock, $0.001 par value; 350,000,000 authorized shares; 273,277,566 shares issued and 272,738,345 shares outstanding at June 30, 2014; 218,783,540 shares issued and 218,244,319 shares outstanding at December 31, 2013	270			215
Subscription rights, $0.001 par value; none issued and outstanding at June 30, 2014; 54,574,734 issued and outstanding at December 31, 2013	—			55
Additional paid-in capital	3,497,849			3,219,748
Accumulated deficit	(3,094,058		)	(3,064,634		)
Treasury stock, at cost; 539,221 shares at June 30, 2014 and December 31, 2013	(7,479		)	(7,479		)
Total shareholders’ equity	396,582			147,905
Total liabilities and shareholders’ equity	$	2,356,478		$	2,408,628

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands, except per share data)	2014			2013			2014			2013
Revenues:
Oil	$	56,055		$	4,524		$	108,385		$	12,858
Natural gas	125,129			144,347			269,152			271,143
Natural gas liquids	1,782			1,461			3,901			4,554
Total revenues	182,966			150,332			381,438			288,555
Costs and expenses:
Oil and natural gas operating costs	15,827			11,902			34,614			25,519
Production and ad valorem taxes	7,364			3,981			14,973			9,229
Gathering and transportation	26,038			23,408			50,651			47,884
Depletion, depreciation and amortization	67,253			47,388			136,528			88,696
Impairment of oil and natural gas properties	—			—			—			10,707
Accretion of discount on asset retirement obligations	695			556			1,376			1,246
General and administrative	19,504			26,574			36,842			44,558
(Gain) loss on divestitures and other operating items	2,973			2,640			5,719			(182,242		)
Total costs and expenses	139,654			116,449			280,703			45,597
Operating income	43,312			33,883			100,735			242,958
Other income (expense):
Interest expense, net	(25,968		)	(15,105		)	(46,132		)	(35,297		)
Gain (loss) on derivative financial instruments	(14,718		)	55,246			(57,740		)	11,732
Other income	77			158			123			246
Equity income (loss)	(410		)	11,416			701			24,079
Total other income (expense)	(41,019		)	51,715			(103,048		)	760
Income (loss) before income taxes	2,293			85,598			(2,313		)	243,718
Income tax expense	—			—			—			—
Net income (loss)	$	2,293		$	85,598		$	(2,313	)	$	243,718
Earnings (loss) per common share:
Basic:
Net income (loss)	$	0.01		$	0.40		$	(0.01	)	$	1.13
Weighted average common shares outstanding	270,492			214,788			265,631			214,786
Diluted:
Net income (loss)	$	0.01		$	0.40		$	(0.01	)	$	1.13
Weighted average common shares and common share equivalents outstanding	271,226			216,023			265,631			215,347

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(in thousands)	2014			2013
Operating Activities:
Net income (loss)	$	(2,313	)	$	243,718
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	136,528			88,696
Share-based compensation expense	3,252			6,323
Accretion of discount on asset retirement obligations	1,376			1,246
Impairment of oil and natural gas properties	—			10,707
Income from equity method investments	(701		)	(24,079		)
(Gain) loss on derivative financial instruments	57,740			(11,732		)
Cash settlements (payments) of derivative financial instruments	(34,469		)	17,511
Amortization of deferred financing costs and discount on debt issuance	7,697			6,597
Gain on divestitures and other non-operating items	—			(186,350		)
Effect of changes in:
Accounts receivable	30,796			17,728
Other current assets	(577		)	(1,786		)
Accounts payable and other current liabilities	68,793			2,653
Net cash provided by operating activities	268,122			171,232
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(197,341		)	(132,363		)
Property acquisitions	(426		)	(33,390		)
Proceeds from disposition of property and equipment	76,266			613,090
Restricted cash	5,349			27,543
Net changes in advances to joint ventures	(10,540		)	8,276
Equity method investments	1,749			(104		)
Net cash provided by (used in) investing activities	(124,943		)	483,052
Financing Activities:
Borrowings under credit agreements	—			46,757
Repayments under credit agreements	(882,424		)	(644,541		)
Proceeds received from 2022 Notes	500,000			—
Proceeds from issuance of common stock, net	271,772			42
Payment of common stock dividends	(27,066		)	(21,479		)
Deferred financing costs and other	(10,066		)	(265		)
Net cash used in financing activities	(147,784		)	(619,486		)
Net increase (decrease) in cash	(4,605		)	34,798
Cash at beginning of period	50,483			45,644
Cash at end of period	$	45,878		$	80,442
Supplemental Cash Flow Information:
Cash interest payments	$	39,576		$	37,059
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	$	2,955		$	3,055
Capitalized interest	10,255			9,817
Issuance of common stock for director services	129			38
Accrued restricted stock dividends	45			201
Debt assumed upon formation of Compass, net	—			58,613

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Common Stock				Subscription Rights					Treasury Stock					Additional paid-in capital		Accumulated deficit			Total shareholders’ equity
(in thousands)	Shares		Amount		Shares		Amount			Shares		Amount
Balance at December 31, 2012	218,126		$	215	—		$	—		(539	)	$	(7,479	)	$	3,200,067	$	(3,043,410	)	$	149,393
Issuance of common stock	8		—		—		—			—		—			80		—			80
Share-based compensation	—		—		—		—			—		—			9,370		—			9,370
Restricted stock issued, net of cancellations	(227	)	—		—		—			—		—			—		—			—
Common stock dividends	—		—		—		—			—		—			—		(21,679		)	(21,679		)
Net income	—		—		—		—			—		—			—		243,718			243,718
Balance at June 30, 2013	217,907		$	215	—		$	—		(539	)	$	(7,479	)	$	3,209,517	$	(2,821,371	)	$	380,882
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 stock	54,579		55		(54,575	)	(55		)	—		—			271,901		—			271,901
Share-based compensation	—		—		—		—			—		—			6,200		—			6,200
Restricted stock issued, net of cancellations	(84	)	—		—		—			—		—			—		—			—
Common stock dividends	—		—		—		—			—		—			—		(27,111		)	(27,111		)
Net loss	—		—		—		—			—		—			—		(2,313		)	(2,313		)
Balance at June 30, 2014	273,278		$	270	—		$	—		(539	)	$	(7,479	)	$	3,497,849	$	(3,094,058	)	$	396,582

See accompanying notes.

6

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.Organization and basis of presentation

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

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

•East Texas/North Louisiana

The East Texas/North Louisiana region is 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. We serve as the operator for most of our properties in the East Texas/North Louisiana region.

•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 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.

•Compass Production Partners, LP

We have a joint venture with Harbinger Group Inc. ("HGI") in which we own a 25.5% economic interest in shallow conventional assets in East Texas and North Louisiana and shallow Canyon Sand and other assets in the Permian Basin ("Compass Production Partners" or "Compass"). We report our interest in Compass using proportional consolidation. During the second quarter of 2014, the legal name of this entity was changed from EXCO/HGI Production Partners, LP to Compass Production Partners, LP.

The accompanying Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013, Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the six months ended June 30, 2014 and 2013 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 year presentation.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC") and in the opinion of management, such financial statements reflect all adjustments necessary to fairly present the consolidated financial position of EXCO at June 30, 2014 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, 2013, filed with the SEC on February 26, 2014 ("2013 Form 10-K").

7

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.

2.Significant accounting policies

We consider significant accounting policies to be those related to our estimates of proved reserves, accounting for 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 2013 Form 10-K.

Recent accounting pronouncements

In February 2013, the Financial Accounting Standards Board ("FASB"), issued Accounting Standards Update ("ASU") No. 2013-04, Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date ("ASU 2013-04"). ASU 2013-04 provides guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations addressed within existing guidance in GAAP. The update is effective for interim and annual periods beginning after December 15, 2013 and is required to be applied retrospectively to all prior periods presented for those obligations that existed upon adoption of ASU 2013-04. Our adoption of ASU 2013-04 did not have an impact on our consolidated financial condition and results of operations.

In April 2014, the FASB issued ASU No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("ASU 2014-08"). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity's operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. ASU 2014-08 also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. ASU 2014-08 retained the scope exception for oil and gas properties accounted for under the full-cost method and therefore we do not believe the update will have a significant impact on our consolidated financial condition and results of operations. ASU 2014-08 is effective prospectively to all periods beginning after December 15, 2014. We will apply the guidance prospectively to disposal activity, when applicable, occurring after the effective date of ASU 2014-08.

In May 2014, the FASB issued ASU No. 2014-09 Revenue from Contracts with Customers (Topic 606) ("ASU 2014-09"). The FASB and the International Accounting Standards Board ("IASB") jointly issued this comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance under GAAP. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under currently applicable guidance including identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial condition and results of operations.

3.Acquisitions, divestitures and other significant events

Permian Basin transaction

On March 24, 2014, we closed a purchase and sale agreement with a private party for the sale of our interest in certain non-operated assets in the Permian Basin including producing wells and undeveloped acreage for approximately $68.2 million, after final purchase price adjustments. The effective date of the transaction was January 1, 2014. Proceeds from the sale were used to reduce indebtedness under our credit agreement ("EXCO Resources Credit Agreement").

8

4.Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the six months ended June 30, 2014:

(in thousands)
Asset retirement obligations at beginning of period	$	42,954
Activity during the period:
Liabilities incurred during the period	355
Liabilities settled during the period	(17		)
Adjustment to liability due to divestitures	(9		)
Accretion of discount	1,376
Asset retirement obligations at end of period	44,659
Less current portion	191
Long-term portion	$	44,468

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

The accounting for, and disclosure of, oil and natural gas producing activities requires that we choose between two GAAP alternatives: the full cost method or the successful efforts method. 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. Our unproved property costs, which include unproved oil and natural gas properties, properties under development, and major development projects, collectively totaled $369.0 million and $425.3 million as of June 30, 2014 and December 31, 2013, respectively, and are not subject to depletion. 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 extension or discoveries from drilling operations or determination that no proved reserves are attributable to such costs. The majority of our undeveloped properties are held-by-production, which reduces the risk of impairment as a result of lease expirations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. There were no impairments of unproved properties during the six months ended June 30, 2014 and 2013.

We capitalize interest on the costs related to the acquisition of undeveloped acreage in accordance with FASB ASC 835-20, Capitalization of Interest. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest related to these properties. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our acquisition, exploration, exploitation and development activities.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs less estimated salvage value are divided by the total estimated quantities of proved reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded.

Sales, dispositions and other oil and natural gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss, unless the disposition would significantly alter the amortization rate and/or the relationship between capitalized costs and proved reserves.

Pursuant to Rule 4-10(c)(4) of Regulation S-X, 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 a ceiling test 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 Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the proved reserves,

9

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 is computed using the simple average spot price for the trailing 12 month period using the first day of each month. For the 12 months ended June 30, 2014, the trailing 12 month reference prices were $4.10 per Mmbtu for natural gas at Henry Hub ("HH") and $100.11 per Bbl of oil for West Texas Intermediate ("WTI") at Cushing, Oklahoma. The price used for NGLs was $43.83 per Bbl and was based on the trailing 12 month average of realized prices. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test impairments of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedging instruments, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computations.

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.

We did not recognize an impairment to our proved oil and natural gas properties for the three and six months ended June 30, 2014. We did not recognize an impairment to our proved oil and natural gas properties for the three months ended June 30, 2013 and recognized an impairment of $10.7 million for the six months ended June 30, 2013 primarily due to low natural gas prices for the trailing twelve month period at the end of the first quarter of 2013.

6.Earnings per share

The following table presents the basic and diluted earnings (loss) per share computations for the three and six months ended June 30, 2014 and 2013: 

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share data)	2014		2013		2014			2013
Basic net income (loss) per common share:
Net income (loss)	$	2,293	$	85,598	$	(2,313	)	$	243,718
Weighted average common shares outstanding	270,492		214,788		265,631			214,786
Net income (loss) per basic common share	$	0.01	$	0.40	$	(0.01	)	$	1.13
Diluted net income (loss) per common share:
Net income (loss)	$	2,293	$	85,598	$	(2,313	)	$	243,718
Weighted average common shares outstanding	270,492		214,788		265,631			214,786
Dilutive effect of:
Stock options	—		437		—			—
Restricted shares	734		798		—			561
Weighted average common shares and common share equivalents outstanding	271,226		216,023		265,631			215,347
Net income (loss) per diluted common share	$	0.01	$	0.40	$	(0.01	)	$	1.13

Diluted earnings per share for the three and six months ended June 30, 2014 and 2013 is computed in the same manner as basic earnings per share after assuming the issuance of common stock for all potentially dilutive common stock equivalents, which include both stock options and restricted stock awards, whether exercisable or not. The computation of diluted earnings per share excluded 12,855,434 and 12,133,160 antidilutive share equivalents for the three months ended June 30, 2014 and 2013, respectively, and 13,853,885 and 15,837,472 antidilutive share equivalents for the six months ended June 30, 2014 and 2013, respectively. The antidilutive share equivalents primarily consisted of out-of-the-money stock options for the three months ended June 30, 2014 and 2013 and the six months ended June 30, 2013.

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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 instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instruments. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value in earnings.

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

Fair Value of Derivative Financial Instruments

(in thousands)	June 30, 2014			December 31, 2013
Derivative financial instruments - Current assets	$	2,330		$	8,226
Derivative financial instruments - Long-term assets	2,773			6,829
Derivative financial instruments - Current liabilities	(29,451		)	(11,919		)
Derivative financial instruments - Long-term liabilities	(5,454		)	(9,671		)
Net derivative financial instruments	$	(29,802	)	$	(6,535	)

Effect of Derivative Financial Instruments

	Three Months Ended June 30,					Six Months Ended June 30,
(in thousands)	2014			2013		2014			2013
Gain (loss) on derivative financial instruments	$	(14,718	)	$	55,246	$	(57,740	)	$	11,732

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 swap, basis swap and call option contracts. Swap contracts allow us to receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. Basis swap 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. Call options are financial contracts that 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.   

We place our derivative financial instruments with the financial institutions that are lenders under our respective credit agreements 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. We proportionately consolidate the derivative financial instruments entered into by Compass; however, the contracts of Compass involve separate master netting agreements with its counterparties.

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The following table presents the volumes and fair value of our oil and natural gas derivative financial instruments (including our 25.5% proportionate interest in Compass's derivative financial instruments) as of June 30, 2014:

(in thousands, except prices)	Volume Mmbtu/Bbl	Weighted average strike price per Mmbtu/Bbl		Fair value at June 30, 2014
Natural gas:
Swaps:
Remainder of 2014	42,371	$	4.22	(9,600		)
2015	28,287	4.31		2,666
Call options:
Remainder of 2014	10,120	4.29		(3,096		)
2015	20,075	4.29		(6,837		)
Total natural gas				$	(16,867	)
Oil:
Swaps:
Remainder of 2014	829	$	95.03	(6,871		)
2015	976	93.19		(4,221		)
Basis swaps:
Remainder of 2014	92	6.03		297
2015	91	6.10		288
Call options:
Remainder of 2014	184	100.00		(920		)
2015	365	100.00		(1,508		)
Total oil				$	(12,935	)
Total oil and natural gas derivative financial instruments				$	(29,802	)

At December 31, 2013, we had outstanding swap and call option contracts covering 112,348 Mmmbtu and 40,150 Mmmbtu, respectively, of natural gas and we had outstanding swap, basis swap and call option contracts covering 2,192 Mbbls, 274 Mbbls and 730 Mbbls, respectively, of oil.

At June 30, 2014, the average forward NYMEX WTI oil prices per Bbl for the remainder of 2014 and calendar year 2015 were $103.82, and $97.62, respectively, the average forward NYMEX Louisiana Light Sweet ("LLS") oil prices per Bbl for the remainder of 2014 and calendar year 2015 were $106.60, and $100.50, respectively, and the average forward NYMEX HH natural gas prices per Mmbtu for the remainder of 2014 and calendar year 2015 were $4.47 and $4.22, respectively.

As of June 30, 2014, our proportionate share of Compass's derivative swap contracts covered 2,811 Mmmbtu of natural gas at an average price of $4.15 and 47 Mbbls of oil for the remainder of 2014 and 64 Mbbls of oil during 2015 at an average price of $91.87 and $94.98, respectively.

Our derivative financial instruments covered approximately 67% and 58% of production volumes for the three months ended June 30, 2014 and 2013, respectively, and 67% and 52% for the six months ended June 30, 2014 and 2013, respectively.

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.

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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 for such assets or liabilities. During the six months ended June 30, 2014 and 2013 there were no changes in the fair value level classifications. The following table presents a summary of the estimated fair value of our derivative financial instruments as of June 30, 2014 and December 31, 2013.

	June 30, 2014
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(29,802	)	$	—	$	(29,802	)
	December 31, 2013
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(6,535	)	$	—	$	(6,535	)

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 or the credit-adjusted risk-free rate curve of Compass. 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. In addition, the credit-adjusted risk-free rate for Compass is based on the cost of debt 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 and call option 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 and call option contracts for notional Mmbtus of natural gas at posted price indexes, including NYMEX HH swap and call 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 call option contracts. The implied rates of volatility were determined based on average HH natural gas prices.

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

Fair value of other financial instruments

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

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The carrying values of our borrowings under the revolving commitment of the EXCO Resources Credit Agreement and Compass Production Partners 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"), our 8.5% senior unsecured notes due April 15, 2022 ("2022 Notes") and the term loan under the EXCO Resources Credit Agreement ("Term Loan") are presented below.  The estimated fair values of the 2018 Notes, 2022 Notes and Term Loan have been calculated based on market quotes.

	June 30, 2014
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	772,500	$	—	$	—	$	772,500
2022 Notes	541,250		—		—		541,250
	December 31, 2013
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	714,000	$	—	$	—	$	714,000
Term Loan	298,500		—		—		298,500

9.    Debt

Our total debt is summarized as follows:

(in thousands)	June 30, 2014			December 31, 2013
Revolving commitment under EXCO Resources Credit Agreement	$	182,492		$	763,866
Term Loan under EXCO Resources Credit Agreement	—			298,500
Unamortized discount on Term Loan	—			(2,780		)
2018 Notes	750,000			750,000
Unamortized discount on 2018 Notes	(6,637		)	(7,293		)
2022 Notes	500,000			—
Total debt excluding Compass Production Partners	1,425,855			1,802,293
Compass Production Partners Credit Agreement	85,792			88,485
Total debt	1,511,647			1,890,778
Less amounts due within one year	—			31,866
Total debt after one year	$	1,511,647		$	1,858,912

Terms and conditions of our debt obligations as of June 30, 2014 are discussed below.

EXCO Resources Credit Agreement

As of June 30, 2014, the EXCO Resources Credit Agreement had $182.5 million of outstanding indebtedness, $875.0 million of available borrowing base and $685.6 million of unused borrowing base, net of letters of credit. The maturity date of the EXCO Resources Credit Agreement is July 31, 2018.

We closed a rights offering and related private placement of our common stock on January 17, 2014 ("Rights Offering") and received gross proceeds of $272.9 million which we used to reduce the outstanding indebtedness under the EXCO Resources Credit Agreement, including the remainder of the asset sale requirement as well as a portion of the revolving commitment. See further discussion in "Note 13. Rights offering and other equity transactions". Upon repayment of the asset sale requirement, the interest rate on the revolving commitment decreased by 100 basis points.

On April 16, 2014, we closed an offering of $500.0 million in aggregate principal amount of senior unsecured notes and utilized the proceeds to fully repay the Term Loan and the remaining proceeds were used to reduce outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement. See further discussion of the 2022 Notes below.

In April 2014, our borrowing base under the revolving commitment of the EXCO Resources Credit Agreement was reduced to $875.0 million in connection with the semi-annual borrowing base redetermination and the issuance of the 2022 Notes. Subsequent redeterminations will occur semi-annually with us and the lenders having the right to request interim

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unscheduled redeterminations in certain circumstances. The interest rate grid for the revolving commitment under the EXCO Resources Credit Agreement ranges 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 June 30, 2014, the one month LIBOR was 0.2%, which resulted in an interest rate of approximately 1.9% on the revolving commitment.

The EXCO Resources Credit Agreement sets forth the terms and conditions under which we are permitted to pay a cash dividend on our common stock. In July 2014, we amended the EXCO Resources Credit Agreement to provide that we may declare and pay cash dividends on our common stock in an amount not to exceed a cumulative total of $75.0 million in any four consecutive fiscal quarters, provided that, as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) we have at least 10% of our revolving commitment, as defined in the EXCO Resources Credit Agreement, available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes and 2022 Notes.

As of June 30, 2014, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:

• maintain a consolidated current ratio (as defined in the EXCO Resources Credit Agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and

• not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter.

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 2014 and 2015, 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.

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 with BG Group, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.

As of June 30, 2014, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at June 30, 2014 was $6.6 million. Interest accrues at 7.5% per annum and is payable semi-annually in arrears on March 15 and September 15 of each year.

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

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

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

• make certain investments;

• create liens on our assets;

• enter into sale/leaseback transactions;

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

• engage in transactions with our affiliates;

• transfer or issue shares of stock of subsidiaries;

• transfer or sell assets; and

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

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2022 Notes

On April 16, 2014, we completed a public offering of $500.0 million in aggregate principal amount of senior unsecured notes due April 15, 2022. We received net proceeds of approximately $490.0 million after offering fees and expenses. 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, with payments commencing on October 15, 2014. We used a portion of the net proceeds from the 2022 Notes offering to repay the $297.8 million outstanding principal balance on the Term Loan and the remaining proceeds were used to reduce outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement.

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.

Compass Production Partners Credit Agreement

As of June 30, 2014, the Compass Production Partners Credit Agreement had a borrowing base of $400.0 million. The borrowing base is redetermined semi-annually, with Compass and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. The Compass Production Partners Credit Agreement matures on February 14, 2018.

Borrowings under the Compass Production Partners Credit Agreement are secured by properties owned by Compass and we do not guarantee Compass's debt. Compass is not a guarantor of the EXCO Resources Credit Agreement, the 2018 Notes or the 2022 Notes. As of June 30, 2014, $337.0 million was drawn under the Compass Production Partners Credit Agreement, and our proportionate share of the obligation was $85.8 million. The interest rate grid ranges from LIBOR plus 175 bps to 275 bps (or ABR plus 75 bps to 175 bps), depending on the percentages of drawn balances to the borrowing base as defined in the agreement. On June 30, 2014, the interest rate on the outstanding borrowings was approximately 2.7%.

As of June 30, 2014, Compass was in compliance with the financial covenants contained in the Compass Production Partners Credit Agreement, which require that it:

• maintain a consolidated current ratio (as defined in the Compass Production Partners Credit Agreement) of at least 1.0 to1.0 as of the end of any fiscal quarter; and

• not permit the ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the Compass Production Partners Credit Agreement) to be greater than 4.5 to1.0 at the end of any fiscal quarter.

The foregoing descriptions are not complete and are qualified in their entirety by the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and 2022 Notes, and the Compass Production Partners Credit Agreement.

10.    Dividends

On May 22, 2014, our board of directors approved a cash dividend of $0.05 per share for the second quarter of 2014. The total cash dividend was $13.6 million, of which $13.5 million was paid on June 16, 2014 to holders of record as of June 2, 2014 and the remainder was accrued to be paid to holders of restricted shares upon vesting. Total dividends paid to our shareholders for the six months ended June 30, 2014 were $27.1 million.

The declaration of any future dividends, as well as the establishment of record and payment dates, is subject to the review and approval of our board of directors. Furthermore, any future declaration of dividends is subject to limitations under the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the indenture governing the 2022 Notes.

11.    Income taxes

We evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial deferred tax assets primarily due to losses arising from impairments to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances decreased $3.5 million for the six months ended June 30, 2014. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $888.1 million which have fully offset our deferred tax assets as of June 30, 2014. The valuation allowances will continue to be recognized until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowances do not impact future utilization of the underlying tax attributes.

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12.     Related party transactions

OPCO serves as the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis. There are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the three and six months ended June 30, 2014 and 2013, these transactions included the following:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2014		2013		2014		2013
Advances to OPCO	$	—	$	4,478	$	—	$	21,910
Amounts received from OPCO	11,259		10,012		20,971		19,975

As of June 30, 2014 and December 31, 2013, the amounts owed under the service agreement were as follows:

(in thousands)	June 30, 2014		December 31, 2013
Amounts due to EXCO (1)	$	8,999	$	2,283
Amounts due from EXCO (1)	—		—

(1) OPCO is the operator of our wells in the Appalachia JV and we advance funds to OPCO on an as needed basis, which are recorded in "Other current assets" on our Consolidated Balance Sheets. Any amounts we owe 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 Consolidated Balance Sheets.

Other related party transactions

Investment accounts managed by Invesco Advisers, Inc. were lenders under the Term Loan of the EXCO Resources Credit Agreement. Invesco Advisers, Inc. is an indirect owner of WL Ross & Co. LLC ("WL Ross"). Wilbur L. Ross, Jr., the Chairman and Chief Executive Officer at WL Ross, serves on EXCO’s board of directors. Invesco Advisers, Inc. held approximately 10% of total borrowings under the Term Loan until the Term Loan was repaid with proceeds received from the issuance of 2022 Notes.

13.    Rights offering and other equity transactions

Rights offering

We closed a rights offering and related private placement of our common stock on January 17, 2014 which resulted in the issuance of 54,574,734 shares of common stock for gross proceeds of $272.9 million. In connection with the Rights Offering, we entered into investment agreements ("Investment Agreements") with certain affiliates of WL Ross and Hamblin Watsa Investment Counsel Ltd. ("Hamblin Watsa") pursuant to which, subject to the terms and conditions thereof, each of them severally agreed to subscribe for and purchase, in a private placement, its respective pro rata portion of shares under the basic subscription right and all unsubscribed shares under the over-subscription privilege subject to the pro rata allocation among the subscription rights holders who elected to exercise their over-subscription privilege. In connection with the Rights Offering and related transactions under the Investment Agreements, WL Ross and Hamblin Watsa purchased 19,599,973 and 6,726,712 shares, respectively, pursuant to their basic subscription rights and the over-subscription privilege. After giving effect to the Rights Offering, WL Ross and Hamblin Watsa owned 18.7% and 6.4%, respectively of the Company's outstanding common shares as of January 17, 2014.

Preferred Stock

We canceled all classes of our preferred stock during the six months ended June 30, 2014. As of the date of cancellation and December 31, 2013, we had 10,000,000 shares of preferred stock authorized with no shares of preferred stock issued and outstanding. Our issued and outstanding shares of capital stock consist solely of shares of common stock.

14. Condensed consolidating financial statements

As of June 30, 2014, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes and 2022 Notes. All of our non-guarantor subsidiaries were considered

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unrestricted subsidiaries under the indenture governing the 2018 Notes and 2022 Notes, with the exception of our equity investment in OPCO. As of and for the six months ended June 30, 2014, our equity method investment in OPCO represented $11.0 million of equity method investments and contributed $1.9 million of equity method losses.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2018 Notes and 2022 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by some 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)

June 30, 2014

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	59,757		$	(21,512	)	$	7,633		$	—		$	45,878
Restricted cash	—			15,221			—			—			15,221
Other current assets	11,484			180,137			5,873			—			197,494
Total current assets	71,241			173,846			13,506			—			258,593
Equity investments	—			—			56,514			—			56,514
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			366,219			2,781			—			369,000
Proved developed and undeveloped oil and natural gas properties	332,418			3,282,905			121,665			—			3,736,988
Accumulated depletion	(330,571		)	(1,965,093		)	(21,310		)	—			(2,316,974		)
Oil and natural gas properties, net	1,847			1,684,031			103,136			—			1,789,014
Gathering, office, field and other equipment, net	2,410			27,599			21,379			—			51,388
Investments in and advances to affiliates, net	1,774,109			—			—			(1,774,109		)	—
Deferred financing costs, net	34,103			—			908			—			35,011
Derivative financial instruments	2,756			—			17			—			2,773
Goodwill	13,293			149,862			—			—			163,155
Other assets	3			27			—			—			30
Total assets	$	1,899,762		$	2,035,365		$	195,460		$	(1,774,109	)	$	2,356,478
Liabilities and shareholders' equity
Current liabilities	$	71,629		$	315,170		$	11,528		$	—		$	398,327
Long-term debt	1,425,855			—			85,792			—			1,511,647
Deferred income taxes	—			—			—			—			—
Other long-term liabilities	5,696			35,221			9,005			—			49,922
Payable to parent	—			2,076,680			32,466			(2,109,146		)	—
Total shareholders' equity	396,582			(391,706		)	56,669			335,037			396,582
Total liabilities and shareholders' equity	$	1,899,762		$	2,035,365		$	195,460		$	(1,774,109	)	$	2,356,478

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2013

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	81,840		$	(35,892	)	$	4,535		$	—		$	50,483
Restricted cash	���			20,570			—			—			20,570
Other current assets	22,533			206,708			5,560			—			234,801
Total current assets	104,373			191,386			10,095			—			305,854
Equity investments	—			—			57,562			—			57,562
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	6,758			415,290			3,259			—			425,307
Proved developed and undeveloped oil and natural gas properties	337,972			3,097,335			118,903			—			3,554,210
Accumulated depletion	(330,086		)	(1,840,332		)	(13,046		)	—			(2,183,464		)
Oil and natural gas properties, net	14,644			1,672,293			109,116			—			1,796,053
Gathering, office, field and other equipment, net	3,479			24,612			22,248			—			50,339
Investments in and advances to affiliates, net	1,834,197			—			—			(1,834,197		)	—
Deferred financing costs, net	27,771			—			1,036			—			28,807
Derivative financial instruments	6,829			—			—			—			6,829
Goodwill	13,293			149,862			—			—			163,155
Other assets	2			27			—			—			29
Total assets	$	2,004,588		$	2,038,180		$	200,057		$	(1,834,197	)	$	2,408,628
Liabilities and shareholders' equity
Current liabilities	$	76,174		$	264,485		$	8,511		$	—		$	349,170
Long-term debt	1,770,427			—			88,485			—			1,858,912
Deferred income taxes	—			—			—			—			—
Other long-term liabilities	10,082			33,831			8,728			—			52,641
Payable to parent	—			2,230,108			35,777			(2,265,885		)	—
Total shareholders' equity	147,905			(490,244		)	58,556			431,688			147,905
Total liabilities and shareholders' equity	$	2,004,588		$	2,038,180		$	200,057		$	(1,834,197	)	$	2,408,628

20

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2014

(in thousands)	Resources			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	306		$	169,795	$	12,865		$	—		$	182,966
Costs and expenses:
Oil and natural gas production	76			18,196		4,919			—			23,191
Gathering and transportation	—			24,899		1,139			—			26,038
Depletion, depreciation and amortization	727			61,840		4,686			—			67,253
Accretion of discount on asset retirement obligations	4			522		169			—			695
General and administrative	962			17,949		593			—			19,504
Other operating items	(12		)	2,977		8			—			2,973
Total costs and expenses	1,757			126,383		11,514			—			139,654
Operating income (loss)	(1,451		)	43,412		1,351			—			43,312
Other income (expense):
Interest expense, net	(25,301		)	—		(667		)	—			(25,968		)
Loss on derivative financial instruments	(13,958		)	—		(760		)	—			(14,718		)
Other income	59			14		4			—			77
Equity loss	—			—		(410		)	—			(410		)
Net income from consolidated subsidiaries	42,944			—		—			(42,944		)	—
Total other income (expense)	3,744			14		(1,833		)	(42,944		)	(41,019		)
Income (loss) before income taxes	2,293			43,426		(482		)	(42,944		)	2,293
Income tax expense	—			—		—			—			—
Net income (loss)	$	2,293		$	43,426	$	(482	)	$	(42,944	)	$	2,293

21

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2013

(in thousands)	Resources			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	74		$	137,318	$	12,940		$	—		$	150,332
Costs and expenses:
Oil and natural gas production	71			10,559		5,253			—			15,883
Gathering and transportation	—			22,500		908			—			23,408
Depletion, depreciation and amortization	1,192			42,761		3,435			—			47,388
Accretion of discount on asset retirement obligations	4			396		156			—			556
General and administrative	9,640			16,421		513			—			26,574
Other operating items	745			1,904		(9		)	—			2,640
Total costs and expenses	11,652			94,541		10,256			—			116,449
Operating income (loss)	(11,578		)	42,777		2,684			—			33,883
Other income (expense):
Interest expense, net	(14,298		)	—		(807		)	—			(15,105		)
Gain on derivative financial instruments	51,495			455		3,296			—			55,246
Other income	82			76		—			—			158
Equity income	—			—		11,416			—			11,416
Net income from consolidated subsidiaries	59,897			—		—			(59,897		)	—
Total other income	97,176			531		13,905			(59,897		)	51,715
Income before income taxes	85,598			43,308		16,589			(59,897		)	85,598
Income tax expense	—			—		—			—			—
Net income	$	85,598		$	43,308	$	16,589		$	(59,897	)	$	85,598

22

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2014

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	3,296		$	351,856		$	26,286		$	—		$	381,438
Costs and expenses:
Oil and natural gas production	375			39,617			9,595			—			49,587
Gathering and transportation	—			48,348			2,303			—			50,651
Depletion, depreciation and amortization	1,884			125,507			9,137			—			136,528
Accretion of discount on asset retirement obligations	9			1,032			335			—			1,376
General and administrative	727			34,795			1,320			—			36,842
Other operating items	(16		)	5,731			4			—			5,719
Total costs and expenses	2,979			255,030			22,694			—			280,703
Operating income	317			96,826			3,592			—			100,735
Other income (expense):
Interest expense, net	(44,796		)	—			(1,336		)	—			(46,132		)
Loss on derivative financial instruments	(54,637		)	—			(3,103		)	—			(57,740		)
Other income (loss)	152			(37		)	8			—			123
Equity income	—			—			701			—			701
Net income from consolidated subsidiaries	96,651			—			—			(96,651		)	—
Total other expense	(2,630		)	(37		)	(3,730		)	(96,651		)	(103,048		)
Income (loss) before income taxes	(2,313		)	96,789			(138		)	(96,651		)	(2,313		)
Income tax expense	—			—			—			—			—
Net income (loss)	$	(2,313	)	$	96,789		$	(138	)	$	(96,651	)	$	(2,313	)

23

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2013

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	8,120		$	261,792		$	18,643		$	—		$	288,555
Costs and expenses:
Oil and natural gas production	2,283			24,664			7,801			—			34,748
Gathering and transportation	—			46,507			1,377			—			47,884
Depletion, depreciation and amortization	3,799			80,289			4,608			—			88,696
Impairment of oil and natural gas properties	—			10,707			—			—			10,707
Accretion of discount on asset retirement obligations	54			945			247			—			1,246
General and administrative	10,293			33,384			881			—			44,558
Gain on divestitures and other operating items	(25,229		)	(157,000		)	(13		)	—			(182,242		)
Total costs and expenses	(8,800		)	39,496			14,901			—			45,597
Operating income	16,920			222,296			3,742			—			242,958
Other income (expense):
Interest expense, net	(34,175		)	—			(1,122		)	—			(35,297		)
Gain (loss) on derivative financial instruments	11,693			(235		)	274			—			11,732
Other income	129			115			2			—			246
Equity income	—			—			24,079			—			24,079
Net earnings from consolidated subsidiaries	249,151			—			—			(249,151		)	—
Total other income (expense)	226,798			(120		)	23,233			(249,151		)	760
Income before income taxes	243,718			222,176			26,975			(249,151		)	243,718
Income tax expense	—			—			—			—			—
Net income	$	243,718		$	222,176		$	26,975		$	(249,151	)	$	243,718

24

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2014

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(54,003	)	$	310,651		$	11,474		$	—		$	268,122
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(1,639		)	(193,606		)	(2,522		)	—			(197,767		)
Proceeds from disposition of property and equipment	68,242			8,017			7			—			76,266
Restricted cash	—			5,349			—			—			5,349
Net changes in advances to joint ventures	—			(10,540		)	—			—			(10,540		)
Equity method investments	—			1,749			—			—			1,749
Distributions received from Compass	3,311			—			—			(3,311		)	—
Advances/investments with affiliates	107,240			(107,240		)	—			—			—
Net cash provided by (used in) investing activities	177,154			(296,271		)	(2,515		)	(3,311		)	(124,943		)
Financing Activities:
Repayments under credit agreements	(879,874		)	—			(2,550		)	—			(882,424		)
Proceeds received from 2022 Notes	500,000			—			—			—			500,000
Proceeds from issuance of common stock, net	271,772			—			—			—			271,772
Payment of common stock dividends	(27,066		)	—			—			—			(27,066		)
Compass cash distribution	—			—			(3,311		)	3,311			—
Deferred financing costs and other	(10,066		)	—			—			—			(10,066		)
Net cash provided by (used in) financing activities	(145,234		)	—			(5,861		)	3,311			(147,784		)
Net increase (decrease) in cash	(22,083		)	14,380			3,098			—			(4,605		)
Cash at beginning of period	81,840			(35,892		)	4,535			—			50,483
Cash at end of period	$	59,757		$	(21,512	)	$	7,633		$	—		$	45,878

25

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2013

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(3,892	)	$	168,302		$	6,822		$	—		$	171,232
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(8,907		)	(120,434		)	(36,412		)	—			(165,753		)
Restricted cash	—			27,543			—			—			27,543
Equity method investments	—			(104		)	—			—			(104		)
Proceeds from disposition of property and equipment	244,499			368,591			—			—			613,090
Distributions received from Compass	1,275			—			—			(1,275		)	—
Net changes in advances to joint ventures	—			8,276			—			—			8,276
Advances/investments with affiliates	462,020			(462,020		)	—			—			—
Net cash provided by (used in) investing activities	698,887			(178,148		)	(36,412		)	(1,275		)	483,052
Financing Activities:
Borrowings under credit agreements	10,000			—			36,757			—			46,757
Repayments under credit agreements	(643,266		)	—			(1,275		)	—			(644,541		)
Proceeds from issuance of common stock	42			—			—			—			42
Payment of common stock dividends	(21,479		)	—			—			—			(21,479		)
Compass cash distribution	—			—			(1,275		)	1,275			—
Deferred financing costs and other	(32		)	—			(233		)	—			(265		)
Net cash provided by (used in) financing activities	(654,735		)	—			33,974			1,275			(619,486		)
Net increase (decrease) in cash	40,260			(9,846		)	4,384			—			34,798
Cash at beginning of period	65,791			(20,147		)	—			—			45,644
Cash at end of period	$	106,051		$	(29,993	)	$	4,384		$	—		$	80,442

26

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

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

Forward-looking statements

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

• our future financial and operating performance and results;

• our business strategy;

• market prices;

• our future use of derivative financial instruments; and

• our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

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

• fluctuations in the prices of oil, natural gas and natural gas liquids;

• the availability of oil, natural gas and natural gas liquids;

• future capital requirements and availability of financing;

• our ability to meet our current and future debt service obligations;

• 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 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;

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

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

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

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

• potential acts of terrorism;

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

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

• fluctuations in interest rates; and

27

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

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, 2013, filed with the Securities and Exchange Commission ("SEC") on February 26, 2014.

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, while continuing to evaluate complementary acquisitions that meet our strategic and financial objectives. We plan to carry out this strategy by leveraging our management and technical team’s experience, exploiting our multi-year inventory of development drilling locations in our shale plays, actively seeking acquisition opportunities, managing our liquidity and enhancing financial flexibility. We believe this 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 complementary acquisitions.

Recent developments

Rights Offering

We closed a rights offering and related private placement of our common stock ("Rights Offering") on January 17, 2014 which resulted in the issuance of 54,574,734 shares of common stock for gross proceeds of $272.9 million. In connection with the Rights Offering, we entered into investment agreements ("Investment Agreements") with certain affiliates of WL Ross & Co. LLC ("WL Ross") and Hamblin Watsa Investment Counsel Ltd. ("Hamblin Watsa") pursuant to which, subject to the terms and conditions thereof, each of them severally agreed to subscribe for and purchase, in a private placement, its respective pro rata portion of shares under the basic subscription right and all unsubscribed shares under the over-subscription privilege subject to the pro rata allocation among the subscription rights holders who elected to exercise their over-subscription privilege. In connection with the Rights Offering and related transactions under the Investment Agreements, WL Ross and Hamblin Watsa purchased 19,599,973 and 6,726,712 shares, respectively, pursuant to their basic subscription rights and the over-subscription privilege. After giving effect to the Rights Offering, WL Ross and Hamblin Watsa owned 18.7% and 6.4%, respectively of the Company's outstanding common shares as of January 17, 2014. We used the proceeds to reduce outstanding indebtedness under our credit agreement ("EXCO Resources Credit Agreement"), including the remainder of the asset sale requirement as well as a portion of the indebtedness outstanding under the revolving commitment.

Permian Basin transaction

On March 24, 2014, we closed a purchase and sale agreement with a private party for the sale of our interest in certain non-operated assets in the Permian Basin including producing wells and undeveloped acreage for approximately $68.2 million, after final purchase price adjustments. The effective date of the transaction was January 1, 2014. Proceeds from the sale were used to reduce outstanding indebtedness under the EXCO Resources Credit Agreement.

28

2022 Notes

On April 16, 2014, we completed a public offering of $500.0 million in aggregate principal amount of senior notes due April 15, 2022 ("2022 Notes"). We received net proceeds of approximately $490.0 million after offering fees and expenses. The 2022 Notes bear interest at a rate of 8.5% per annum, payable in arrears on April 15 and October 15 of each year, with payments commencing on October 15, 2014. We used the net proceeds from the 2022 Notes to repay indebtedness under the EXCO Resources Credit Agreement, including the $297.8 million outstanding principal balance on the term loan ("Term Loan") and the remaining proceeds were used to reduce outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement. In April 2014, our borrowing base under the revolving commitment of the EXCO Resources Credit Agreement was reduced to $875.0 million in connection with the semi-annual borrowing base redetermination and the issuance of the 2022 Notes.

Critical accounting policies

We consider accounting policies related to our estimates of proved reserves, accounting for oil and natural gas properties, derivatives, 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 Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 26, 2014.

29

Our results of operations

A summary of key financial data for the three and six months ended June 30, 2014 and 2013 related to our results of operations is presented below:

	Three Months Ended June 30,					Quarter to quarter change			Six Months Ended June 30,					Period to period change
(dollars in thousands, except per unit prices)	2014			2013					2014			2013
Production:
Oil (Mbbls)	579			50		529			1,172			152		1,020
Natural gas (Mmcf)	31,006			37,695		(6,689		)	63,728			77,288		(13,560		)
Natural gas liquids (Mbbls)	65			43		22			124			125		(1		)
Total production (Mmcfe) (1)	34,870			38,253		(3,383		)	71,504			78,950		(7,446		)
Average daily production (Mmcfe)	383			420		(37		)	395			436		(41		)
Revenues before derivative financial instrument activities:
Oil	$	56,055		$	4,524	$	51,531		$	108,385		$	12,858	$	95,527
Natural gas	125,129			144,347		(19,218		)	269,152			271,143		(1,991		)
Natural gas liquids	1,782			1,461		321			3,901			4,554		(653		)
Total revenues	$	182,966		$	150,332	$	32,634		$	381,438		$	288,555	$	92,883
Oil and natural gas derivative financial instruments:
Gain (loss) on derivative financial instruments	$	(14,718	)	$	55,246	$	(69,964	)	$	(57,740	)	$	11,732	$	(69,472	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	96.81		$	90.48	$	6.33		$	92.48		$	84.59	$	7.89
Natural gas (per Mcf)	4.04			3.83		0.21			4.22			3.51		0.71
Natural gas liquids (per Bbl)	27.42			33.98		(6.56		)	31.46			36.43		(4.97		)
Natural gas equivalent (per Mcfe)	5.25			3.93		1.32			5.33			3.65		1.68
Costs and expenses:
Oil and natural gas operating costs	$	15,827		$	11,902	$	3,925		$	34,614		$	25,519	$	9,095
Production and ad valorem taxes	7,364			3,981		3,383			14,973			9,229		5,744
Gathering and transportation	26,038			23,408		2,630			50,651			47,884		2,767
Depletion	65,800			45,366		20,434			133,536			84,357		49,179
Depreciation and amortization	1,453			2,022		(569		)	2,992			4,339		(1,347		)
General and administrative (2)	19,504			26,574		(7,070		)	36,842			44,558		(7,716		)
Interest expense, net	25,968			15,105		10,863			46,132			35,297		10,835
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.45		$	0.31	$	0.14		$	0.48		$	0.32	$	0.16
Production and ad valorem taxes	0.21			0.10		0.11			0.21			0.12		0.09
Gathering and transportation	0.75			0.61		0.14			0.71			0.61		0.10
Depletion	1.89			1.19		0.70			1.87			1.07		0.80
Depreciation and amortization	0.04			0.05		(0.01		)	0.04			0.05		(0.01		)
General and administrative	0.56			0.69		(0.13		)	0.52			0.56		(0.04		)
Net income (loss)	$	2,293		$	85,598	$	(83,305	)	$	(2,313	)	$	243,718	$	(246,031	)

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

(2) Share-based compensation expense included in general and administrative expenses was $1.7 million and $4.6 million for the three months ended June 30, 2014 and 2013, respectively, and $3.3 million and $6.3 millionfor the six months endedJune 30, 2014 and 2013, respectively.

The following is a discussion of our financial condition and results of operations for the three and six months ended June 30, 2014 and 2013.

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The comparability of our results of operations for June 30, 2014 and 2013 was affected by:

• the acquisitions of the Haynesville and Eagle Ford assets during the third quarter of 2013;

• the formation of Compass Production Partners, LP ("Compass") during the first quarter of 2013;

• the sale of our equity interest in TGGT Holdings, LLC ("TGGT") during the fourth quarter of 2013;

• fluctuations in oil, natural gas and NGL 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 2013;

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

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

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

• significant changes in our capital structure as a result of the Rights Offering and debt financing transactions.

General

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

• the level of domestic production and economic activity;

• the domestic oversupply of natural gas;

• the inability to export domestic oil and natural gas;

• the level of domestic and industrial demand for natural gas for utilities and manufacturing operations;

• the available capacity at natural gas storage facilities and quantities of inventories in storage;

• the availability of imported oil and natural gas;

• actions taken by foreign oil producing nations;

• the cost and availability of natural gas pipelines with adequate capacity and other transportation facilities;

• the cost and availability of other competitive fuels;

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

• the extent of governmental regulation and taxation (under both present and future legislation) of the exploration, production, refining, transportation, pricing, use and allocation of oil, natural gas, refined products and substitute fuels; and

• trends in fuel use and government regulations that encourage less fuel use and encourage or mandate alternative fuel use.

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.

Summary

For the three months ended June 30, 2014 and 2013, we reported net income of $2.3 million and $85.6 million, respectively. The decrease in net income was primarily due to volatility in commodity prices which resulted in losses on derivative financial instruments of $14.7 million for the three months ended June 30, 2014 compared to gains of $55.2 million for the same period in the prior year. This was partially offset by an increase in operating income of $9.4 million due to higher commodity prices and the acquisition of Haynesville and Eagle Ford assets.

For the six months ended June 30, 2014 and 2013, we reported a net loss of $2.3 million and net income $243.7 million, respectively. The decrease in net income was primarily due to lower operating income resulting from the gain of $186.4 million on the divestiture recorded during the six months ended June 30, 2013 in connection with the formation of Compass. This was partially offset by higher commodity prices and the acquisition of Haynesville and Eagle Ford assets. The decrease in net income was also due to volatility in commodity prices which resulted in losses on derivative financial instruments of $57.7 million for the six months ended June 30, 2014 compared to gains of $11.7 million for the same period in the prior year and lower equity income due to the sale of our investment in TGGT.

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Presentation of results of operations

Our discussion of production, revenues and direct operating expenses is based on our producing regions and Compass. Compass includes conventional non-shale assets in East Texas, North Louisiana and the Permian Basin. Prior to the formation of Compass on February 14, 2013, the operating results of the properties contributed by EXCO were included within the East Texas/North Louisiana and Other regions in our discussion of production, revenues and direct operating expenses. The operating results of Compass represent our proportionate interest subsequent to its formation on February 14, 2013. We closed the acquisition of assets in the Eagle Ford shale and formed our South Texas region on July 31, 2013.

Oil and natural gas production, revenues and prices

The following tables present our production, revenue and average sales prices for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30,
	2014					2013					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:
East Texas/North Louisiana	23,368	$	98,681	$	4.22	29,850	$	112,798	$	3.78	(6,482	)	$	(14,117	)	$	0.44
South Texas	3,575	50,890		14.23		—	—		—		3,575		50,890			14.23
Appalachia	5,629	20,225		3.59		5,840	24,520		4.20		(211	)	(4,295		)	(0.61		)
Other	36	306		8.50		24	75		3.13		12		231			5.37
Compass	2,262	12,864		5.69		2,539	12,939		5.10		(277	)	(75		)	0.59
Total	34,870	$	182,966	$	5.25	38,253	$	150,332	$	3.93	(3,383	)	$	32,634		$	1.32

	Six Months Ended June 30,
	2014					2013					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:
East Texas/North Louisiana	48,598	$	214,478	$	4.41	63,299	$	219,585	$	3.47	(14,701	)	$	(5,107	)	$	0.94
South Texas	7,079	95,708		13.52		—	—		—		7,079		95,708			13.52
Appalachia	11,125	41,673		3.75		10,906	42,207		3.87		219		(534		)	(0.12		)
Other	261	3,294		12.62		1,027	8,120		7.91		(766	)	(4,826		)	4.71
Compass	4,441	26,285		5.92		3,718	18,643		5.01		723		7,642			0.91
Total	71,504	$	381,438	$	5.33	78,950	$	288,555	$	3.65	(7,446	)	$	92,883		$	1.68

Production for the three months ended June 30, 2014decreased by 3.4 Bcfe, or 9%, as compared with the same period in 2013. The decrease in production in the East Texas/North Louisiana region was primarily due to production declines from changes in our drilling program. The production declines were primarily the result of reduced development activities within this region compared to periods prior to 2013. Our drilling activities in the Haynesville shale resulted in 12 wells turned-to-sales for the three months ended June 30, 2014 compared to 15 wells turned-to-sales for the three months ended June 30, 2013. Our production in the South Texas region was 3.6 Bcfe for the three months ended June 30, 2014, which consisted of 534 Mbbls of oil, 23 Mbbls of natural gas liquids and 235 Mmcf of natural gas. We turned-to-sales 13 wells in the Eagle Ford shale during the three months ended June 30, 2014. The decrease in production of 0.2 Bcfe in the Appalachia region was a result of production declines following the suspension of our drilling program during the second half of 2013. The decrease in our proportionate share of Compass's production was primarily due to natural production declines related to its properties in East Texas and North Louisiana.

Oil and natural gas revenues for the three months ended June 30, 2014increased by $32.6 million, or 22%, as compared with the same period in 2013. The increase in revenues was primarily the result of an increase in oil and natural gas prices and the acquisition of Haynesville and Eagle Ford assets. Our average natural gas sales price increased 5% to $4.04 per Mcf for the three months ended June 30, 2014 from $3.83 per Mcf for the three months ended June 30, 2013. Our average sales price for natural gas during 2014 was positively impacted by higher market prices and was partially offset by the widening of

32

differentials in Appalachia as a result of an oversupply of natural gas in the Northeast region. Our average sales price of oil per Bbl increased 7% to $96.81 per Bbl for the three months ended June 30, 2014 from $90.48 per Bbl for the three months ended June 30, 2013. Our average sales price for oil in the South Texas region is most closely correlated to the Louisiana Light Sweet ("LLS") price index and is presented net of marketing, gathering and transportation costs. Our average sales price of natural gas liquids per Bbl decreased 19% to $27.42 per Bbl for the three months ended June 30, 2014 from $33.98 per Bbl for the three months ended June 30, 2013.

Production for the six months ended June 30, 2014 decreased by 7.4 Bcfe, or 9%, as compared with the same period in 2013. The decrease in production in the East Texas/North Louisiana region was primarily due to production declines resulting from changes in our drilling program and the contribution of properties to Compass. The production declines were primarily the result of reduced development activities within this region compared to periods prior to 2013. Our drilling activities in the Haynesville shale resulted in 14 wells turned-to-sales for the six months ended June 30, 2014 compared to 34 wells turned-to-sales for the six months ended June 30, 2013. The wells turned-to-sales for the six months ended June 30, 2013 primarily consisted of wells drilled during 2012. Our production in the South Texas region was 7.1 Bcfe for the six months ended June 30, 2014, which consisted of 1,059 Mbbls of oil, 39 Mbbls of natural gas liquids and 489 Mmcf of natural gas. We turned-to-sales 26 wells in the Eagle Ford shale during the six months ended June 30, 2014. The increase in production of 0.2 Bcfe in the Appalachia region was a result of our completion activities in the Marcellus shale partially offset by normal production declines. The decrease in production in the Other region was primarily the result of the contribution of properties in the Permian Basin to Compass. The increase in our proportionate share of Compass's production was primarily due to fewer days of production in the prior year as a result of its formation on February 14, 2013.

Oil and natural gas revenues for the six months ended June 30, 2014 increased by $92.9 million, or 32%, as compared with the same period in 2013. The increase in revenues was primarily the result of an increase in oil and natural gas prices and the acquisition of Haynesville and Eagle Ford assets. Our average natural gas sales price increased 20% to $4.22 per Mcf for the six months ended June 30, 2014 from $3.51 per Mcf for the six months ended June 30, 2013. Our average sales price for natural gas during the six months ended June 30, 2014 was positively impacted by higher market prices and was partially offset by the widening of differentials in Appalachia as a result of an oversupply of natural gas in the Northeast region. Our average sales price of oil per Bbl increased 9% to $92.48 per Bbl for the six months ended June 30, 2014 from $84.59 per Bbl for the six months ended June 30, 2013. Our average sales price of natural gas liquids per Bbl decreased 14% to $31.46 per Bbl for the six months ended June 30, 2014 from $36.43 per Bbl for the six months ended June 30, 2013.

Oil and natural gas operating costs

The following tables present our operating costs for the three and six months ended June 30, 2014 and 2013:

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	Three Months Ended June 30,
	2014						2013						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:
East Texas/North Louisiana	$	4,648	$	917	$	5,565	$	3,515	$	1,293	$	4,808	$	1,133		$	(376	)	$	757
South Texas	2,598		173		2,771		—		—		—		2,598			173			2,771
Appalachia	3,711		—		3,711		3,145		—		3,145		566			—			566
Other	66		—		66		62		—		62		4			—			4
Compass	3,174		540		3,714		3,330		557		3,887		(156		)	(17		)	(173		)
Total	$	14,197	$	1,630	$	15,827	$	10,052	$	1,850	$	11,902	$	4,145		$	(220	)	$	3,925
	Three Months Ended June 30,
	2014						2013						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:
East Texas/North Louisiana	$	0.20	$	0.04	$	0.24	$	0.12	$	0.04	$	0.16	$	0.08		$	—		$	0.08
South Texas	0.73		0.05		0.78		—		—		—		0.73			0.05			0.78
Appalachia	0.66		—		0.66		0.54		—		0.54		0.12			—			0.12
Other	1.83		—		1.83		2.58		—		2.58		(0.75		)	—			(0.75		)
Compass	1.40		0.24		1.64		1.31		0.22		1.53		0.09			0.02			0.11
Operating costs per Mcfe	$	0.40	$	0.05	$	0.45	$	0.26	$	0.05	$	0.31	$	0.14		$	—		$	0.14

	Six Months Ended June 30,
	2014						2013						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:
East Texas/North Louisiana	$	8,962	$	2,441	$	11,403	$	8,922	$	2,888	$	11,810	$	40		$	(447	)	$	(407	)
South Texas	8,449		298		8,747		—		—		—		8,449			298			8,747
Appalachia	7,084		6		7,090		6,423		—		6,423		661			6			667
Other	219		—		219		1,522		—		1,522		(1,303		)	—			(1,303		)
Compass	6,072		1,083		7,155		4,982		782		5,764		1,090			301			1,391
Total	$	30,786	$	3,828	$	34,614	$	21,849	$	3,670	$	25,519	$	8,937		$	158		$	9,095
	Six Months Ended June 30,
	2014						2013						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:
East Texas/North Louisiana	$	0.18	$	0.05	$	0.23	$	0.14	$	0.05	$	0.19	$	0.04		$	—		$	0.04
South Texas	1.19		0.04		1.23		—		—		—		1.19			0.04			1.23
Appalachia	0.64		—		0.64		0.59		—		0.59		0.05			—			0.05
Other	0.84		—		0.84		1.48		—		1.48		(0.64		)	—			(0.64		)
Compass	1.37		0.24		1.61		1.34		0.21		1.55		0.03			0.03			0.06
Total	$	0.43	$	0.05	$	0.48	$	0.28	$	0.04	$	0.32	$	0.15		$	0.01		$	0.16

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As shown in the tables above, oil and natural gas operating costs for the three months ended June 30, 2014 increased by $3.9 million, or 33%, as compared with the same period in 2013. The increase in oil and natural gas operating expenses was primarily due to the acquisition of the Eagle Ford assets. Oil and natural gas operating costs for the six months ended June 30, 2014 increased by $9.1 million, or 36%, as compared with the same period in 2013. The increase in oil and natural gas operating expenses was primarily due to the acquisition of the Eagle Ford assets and partially offset by the contribution of properties to Compass.

Oil and natural gas operating costs for the three months ended June 30, 2014 were $0.45 per Mcfe compared to $0.31 per Mcfe for the three months ended June 30, 2013. The net increase in oil and natural gas operating costs per Mcfe is attributable to higher costs associated with our oil production in the South Texas region. The higher costs associated with our oil production include chemical treating programs, water hauling, and maintenance associated with pumping units and tank batteries. Oil and natural gas operating costs for the six months ended June 30, 2014 were $0.48 per Mcfe compared to $0.32 per Mcfe for the six months ended June 30, 2013. The net increase in oil and natural gas operating costs per Mcfe is attributable to higher costs associated with our oil production in the South Texas region. This increase was partially offset by the contribution of properties to Compass, which typically have 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 months ended June 30, 2014 increased by $2.6 million, or 11%, as compared with the same period in 2013. Gathering and transportation expenses were $0.75 per Mcfe for the three months ended June 30, 2014, as compared to $0.61 per Mcfe for the three months ended June 30, 2013. Gathering and transportation expenses for the six months ended June 30, 2014 increased by $2.8 million, or 6%, as compared with the same period in 2013. Gathering and transportation expenses were $0.71 per Mcfe for the six months ended June 30, 2014, as compared to $0.61 per Mcfe for the six months ended June 30, 2013. The increase in gathering and transportation expenses on a per Mcfe basis was primarily due to lower volumes in relation to fixed costs under firm transportation contracts in the East Texas/North Louisiana region. In addition, a marketing arrangement with a significant purchaser of our Haynesville shale production volumes was revised in April 2014 which resulted in higher gathering and transportation expenses.

In our South Texas region, we report our gathering and transportation charges as part of our realized price within revenues based on the net proceeds received from the purchaser. In our East Texas/North Louisiana and Appalachia regions, we either report our gathering and transportation charges as part of our realized prices within revenues or as gathering and transportation expense depending on the type of sales agreement and information received from the purchaser.

35

Production and ad valorem taxes

The following tables present our production and ad valorem taxes on a percentage of revenue basis and per Mcfe basis for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30,
	2014						2013
(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:
East Texas/North Louisiana	$	2,343	2.4	%	$	0.10	$	1,883	1.7	%	$	0.06
South Texas	3,209		6.3	%	0.90		—		—	%	—
Appalachia	597		3.0	%	0.11		725		3.0	%	0.12
Other	11		3.6	%	0.31		6		8.0	%	0.25
Compass	1,204		9.4	%	0.53		1,367		10.6	%	0.54
Total	$	7,364	4.0	%	$	0.21	$	3,981	2.6	%	$	0.10
	Six Months Ended June 30,
	2014						2013
(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:
East Texas/North Louisiana	$	4,713	2.2	%	$	0.10	$	5,033	2.3	%	$	0.08
South Texas	6,461		6.8	%	0.91		—		—	%	—
Appalachia	1,204		2.9	%	0.11		1,400		3.3	%	0.13
Other	156		4.7	%	0.60		758		9.3	%	0.74
Compass	2,439		9.3	%	0.55		2,038		10.9	%	0.55
Total	$	14,973	3.9	%	$	0.21	$	9,229	3.2	%	$	0.12

Production and ad valorem taxes for the three months ended June 30, 2014 increased by $3.4 million, or 85%, as compared with the same period in 2013. Production and ad valorem taxes for the six months ended June 30, 2014 increased by $5.7 million, or 62%, as compared with the same period in 2013. The increase was primarily attributable to higher production and ad valorem taxes associated with oil production in the South Texas region. Additionally, this increase was due to the expiration of severance tax holidays on certain Haynesville shale wells in the East Texas/North Louisiana region. This increase was partially offset by lower production volumes and the decrease in the state of Louisiana severance tax rate to $0.118 per Mcf in July 2013 for wells that did not have a severance tax holiday.

Production and ad valorem tax rates per Mcfe were $0.21 and $0.10 for the three months ended June 30, 2014 and 2013, respectively. Production and ad valorem tax rates per Mcfe were $0.21 and $0.12 for the six months ended June 30, 2014 and 2013, respectively. The rate per Mcfe increased due to higher production and ad valorem taxes per Mcfe associated with oil production in the South Texas region and the expiration of severance tax holidays on certain Haynesville shale wells in the East Texas/North Louisiana region.

In our East Texas/North Louisiana region, we currently receive severance tax holidays on certain Haynesville shale 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 2013, the state of Louisiana decreased its severance tax rate to $0.118 per Mcf from $0.148 per Mcf. In July 2014, the state of Louisiana increased its severance tax rate to $0.163 per Mcf.

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Depletion, depreciation and amortization

Depletion expense for the three months ended June 30, 2014 increased by $20.4 million, or 45%, as compared with the same period in 2013. On a per Mcfe basis, the depletion rate for the three months ended June 30, 2014 was $1.89 per Mcfe, compared with $1.19 per Mcfe in the same period in 2013. Depletion expense for the six months ended June 30, 2014 increased by $49.2 million, or 58%, as compared with the same period in 2013. On a per Mcfe basis, the depletion rate for the six months ended June 30, 2014 was $1.87 per Mcfe, compared with $1.07 per Mcfe in the same period in 2013. The increase in the depletion rate was primarily due to the acquisition of assets in the Haynesville and Eagle Ford shale during the third quarter of 2013 which increased our depletable base. The oil producing assets in the Eagle Ford shale result in a higher depletion rate when calculated on per Mcfe basis compared to the rest of our properties.

Depreciation and amortization costs for the three months ended June 30, 2014decreased by $0.6 million, or 28%, as compared with the same period in 2013. The decrease was primarily due to reduced spending on certain corporate assets. Depreciation and amortization costs for the six months endedJune 30, 2014 decreased by $1.3 million, or 31%, as compared with the same period in 2013. The decrease was due to contribution of gathering assets to Compass in the first quarter of 2013 and reduced spending on certain corporate assets.

Accretion of discount on asset retirement obligations for the three months ended June 30, 2014 increased $0.1 million, or 25%, compared with the same period in 2013. Accretion of discount on asset retirement obligations for the six months endedJune 30, 2014 increased by $0.1 million, or 10%, compared with the same period in 2013. The increase was primarily due to additional accretion of discount on asset retirement obligations of Haynesville and Eagle Ford assets acquired during the third quarter of 2013, partially offset by the contribution of properties to Compass in the first quarter of 2013.

Impairment of oil and natural gas properties

For the three and six months ended June 30, 2014, we did not record an impairment to our oil and natural gas properties. For the three months ended June 30, 2013, we did not record an impairment to our oil and natural gas properties. For the six months ended June 30, 2013, we recorded an impairment of $10.7 million to our oil and natural gas properties primarily due to low natural gas prices for the trailing twelve month period at the end of the first quarter of 2013.

General and administrative

The following table presents our general and administrative expenses for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30,									Six Months Ended June 30,
(in thousands, except per unit rate)	2014			2013			Quarter to quarter change			2014			2013			Period to period change
General and administrative costs:
Gross general and administrative expense	$	33,825		$	39,576		$	(5,751	)	$	64,877		$	71,707		$	(6,830	)
Technical services and service agreement charges	(6,778		)	(6,550		)	(228		)	(12,783		)	(12,885		)	102
Operator overhead reimbursements	(3,480		)	(2,067		)	(1,413		)	(6,833		)	(5,166		)	(1,667		)
Capitalized salaries and share-based compensation	(4,063		)	(4,385		)	322			(8,419		)	(9,098		)	679
General and administrative expense	$	19,504		$	26,574		$	(7,070	)	$	36,842		$	44,558		$	(7,716	)
General and administrative expense per Mcfe	$	0.56		$	0.69		$	(0.13	)	$	0.52		$	0.56		$	(0.04	)

General and administrative expenses for the three and six months ended June 30, 2014 decreased by $7.1 million, or 27%, and $7.7 million, or 17%, respectively, compared with the same periods in prior year. Significant components of the changes in general and administrative expenses were a result of:

• decreased personnel and employee relocation costs of $1.5 million and $2.8 million for the three and six months ended June 30, 2014, respectively, compared to the same periods in the prior year. This decrease is primarily the result of a reduction in our workforce and the centralization of certain functions from the Appalachia region. This decrease was partially offset by $2.2 million in severance costs associated with the reduction in our workforce during the three months ended June 30, 2014.

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• decreased share-based compensation of $2.9 million and $3.2 million for the three and six months ended June 30, 2014, respectively, compared to the same periods in the prior year. This decrease is primarily due to a reduction in headcount and the modification of share-based payments in connection with the retirement of a former executive in the prior year.

• increased operator overhead reimbursements of $1.4 million and $1.7 million for the three and six months ended June 30, 2014, respectively, compared to the same periods in the prior year. The increase is primarily associated with the additional operated wells acquired and developed in the Haynesville and Eagle Ford shales subsequent to June 30, 2013.

(Gain) loss on divestitures and other operating items

(Gain) loss on divestitures and other operating items was a net loss of $3.0 million for the three months ended June 30, 2014 compared with a net loss of $2.6 million for the three months ended June 30, 2013. The net loss for the three months ended June 30, 2014 primarily consisted of expenses related to various litigation. The net loss for the three months ended June 30, 2013 primarily related to expenses incurred in connection with the acquisition of Eagle Ford and Haynesville properties and expenses for various litigation. (Gain) loss on divestitures and other operating items was a net loss of $5.7 million for the six months ended June 30, 2014 compared with a net gain of $182.2 million for the six months ended June 30, 2013. The net loss for the six months ended June 30, 2014 primarily consisted of expenses related to various litigation. The net gain for the six months ended June 30, 2013 was primarily related to the gain of $186.4 million as a result of the contribution of certain oil and natural gas properties to Compass. Partially offsetting the gain were expenses incurred in connection with the acquisition of Eagle Ford and Haynesville properties, expenses related to various litigation and losses related to equipment sales.

Interest expense, net

The following table presents our interest expense, net for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30,									Six Months Ended June 30,
(in thousands)	2014			2013			Quarter to quarter change			2014			2013			Period to period change
Interest expense, net:
2018 Notes	$	14,393		$	14,368		$	25		$	28,780		$	28,731		$	49
2022 Notes	8,854			—			8,854			8,854			—			8,854
EXCO Resources Credit Agreement	5,096			3,559			1,537			13,021			9,273			3,748
Compass Production Partners Credit Agreement	604			691			(87		)	1,210			1,013			197
Amortization of deferred financing costs	2,292			1,178			1,114			4,263			5,991			(1,728		)
Capitalized interest	(5,465		)	(4,738		)	(727		)	(10,255		)	(9,817		)	(438		)
Other	194			47			147			259			106			153
Total interest expense, net	$	25,968		$	15,105		$	10,863		$	46,132		$	35,297		$	10,835

Interest expense, net for the three and six months ended June 30, 2014 increased from the same periods in 2013 primarily due to higher average outstanding indebtedness and a higher average interest rate attributable to the Term Loan and 2022 Notes. The increase was also due to the write-off of the $2.6 million unamortized discount on the Term Loan upon repayment in April 2014.

Derivative financial instruments

Our oil and natural gas derivative financial instruments resulted in a net loss of $14.7 million and a net gain of $55.2 million for the three months ended June 30, 2014 and 2013, respectively. Our oil and natural gas derivative financial instruments resulted in a net loss of $57.7 million and a net gain of $11.7 million for the six months ended June 30, 2014 and 2013, 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 natural gas prices, before and after the impact of the cash settlement of our derivative financial instruments:

	Three Months Ended June 30,								Six Months Ended June 30,
Average realized pricing:	2014			2013		Quarter to quarter change			2014			2013		Period to period change
Natural gas equivalent (Mcfe)	$	5.25		$	3.93	$	1.32		$	5.33		$	3.65	$	1.68
Cash (payments) settlements on derivative financial instruments, per Mcfe	(0.42		)	0.02		(0.44		)	(0.48		)	0.22		(0.70		)
Net price per Mcfe, including derivative financial instruments	$	4.83		$	3.95	$	0.88		$	4.85		$	3.87	$	0.98

Our total cash payments for the three months ended June 30, 2014 were $14.7 million, or $0.42 per Mcfe, compared to cash receipts of $0.8 million, or $0.02 per Mcfe, for the three months ended June 30, 2013. Our total cash payments for the six months ended June 30, 2014 were $34.5 million, or $0.48 per Mcfe, compared to cash receipts of $17.5 million, or $0.22 per Mcfe, for the six months ended June 30, 2013. As noted above, the significant fluctuations between settlements on our derivative financial instruments demonstrate the volatility in commodity prices.

Equity income (loss)

Equity income (loss) decreased by $11.8 million from income of $11.4 million for the three months ended June 30, 2013 to a loss of $0.4 million for the three months ended June 30, 2014. Equity income (loss) decreased by $23.4 million from income of $24.1 million for the six months ended June 30, 2013 to income of $0.7 million for the six months ended June 30, 2014. The decrease in equity income in 2014 was primarily due to the sale of our equity interest in TGGT on November 15, 2013.

Income taxes

Our effective income tax rate for the three and six months ended June 30, 2014 and 2013 was zero, primarily due to prior losses arising from ceiling test impairments which created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our accumulated valuation allowance as of June 30, 2014 was approximately $888.1 million and can be used against future deferred financial 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 162.1% and 150.6% for the three and six months ended June 30, 2014, respectively, and 44.2% and 45.3% for the three and six months ended June 30, 2013, respectively. The effective tax rates, excluding the impact of the valuation allowance, differ from the statutory tax rates primarily due to permanent differences between carrying amounts 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 in 2014 and future years include the following:

• the level of planned drilling activities;

• the results of our ongoing drilling programs;

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

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

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

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

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

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

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• potential acquisitions and/or sales 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;

• reductions to our borrowing base; and

• our ability to maintain compliance with debt covenants.

Recent events affecting liquidity

During the six months ended June 30, 2014, we utilized the proceeds from the Rights Offering, sale of certain assets in the Permian Basin and cash flows from operations to reduce indebtedness under the EXCO Resources Credit Agreement by $387.9 million. On April 16, 2014, we completed a public offering of $500.0 million in aggregate principal amount of senior unsecured notes due April 15, 2022. We received net proceeds of approximately $490.0 million after offering fees and expenses. We used a portion of the net proceeds to repay the $297.8 million outstanding principal balance on the Term Loan and the remaining proceeds were used to reduce the outstanding indebtedness under the revolving commitment of the EXCO Resources Credit Agreement. Our borrowing base under the revolving commitment of the EXCO Resources Credit Agreement was reduced to $875.0 million in connection with the semi-annual borrowing base redetermination and the issuance of the 2022 Notes. As a result of these transactions, our liquidity improved from $224.6 million as of December 31, 2013 to $739.1 million as of June 30, 2014.

While we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities and available borrowing capacity under the EXCO Resources Credit Agreement will be adequate to execute our corporate strategies and to meet debt service obligations, there are certain risks and uncertainties that could negatively impact our results of operations and financial condition. Significant reductions in our borrowing capacity as a result of a redetermination of our borrowing base could have an impact on our capital resources and liquidity. Accordingly, our ability to effectively manage our capital budget is critical to our financial condition, liquidity and results of operations.

The following table presents our liquidity as of June 30, 2014:

(in thousands)	June 30, 2014
EXCO Resources Credit Agreement	$	182,492
2018 Notes (1)	750,000
2022 Notes	500,000
Total debt (2)	$	1,432,492
Net debt	$	1,379,026
Borrowing base	$	875,000
Unused borrowing base (3)	$	685,620
Cash (4) (5)	$	53,466
Unused borrowing base plus cash	$	739,086

(1) Excludes unamortized discount of $6.6 million as of June 30, 2014.

(2) Excludes our proportionate share of the debt related to Compass of $85.8 million as of June 30, 2014.

(3) Net of $6.9 million in letters of credit as of June 30, 2014.

(4) Includes restricted cash of $15.2 million as of June 30, 2014.

(5) Excludes our proportionate share of cash related to Compass of $7.6 million as of June 30, 2014.

Credit agreements and long-term debt

As of June 30, 2014, our consolidated debt consisted of the EXCO Resources Credit Agreement, the 2018 Notes, the 2022 Notes and our 25.5% proportionate share of the Compass Production Partners Credit Agreement (see "Note 9. Debt" in the Notes to our Condensed Consolidated Financial Statements for a further description of each agreement). While our proportionate share of Compass's debt is consolidated, we are not a guarantor of the debt.

As of June 30, 2014, both EXCO and Compass were in compliance with the financial covenants contained in their respective credit agreements, which are presented in the following table. Management believes the following table contains important information related to our liquidity and compliance with the financial covenants of each agreement. However, the information is not complete and is qualified in its entirety by the terms of the EXCO Resources Credit Agreement and the Compass Production Partners Credit Agreement.

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	June 30, 2014
(dollars in millions)	Borrowing base		Outstanding		Covenant type (1)	Required ratio (2)	Actual ratio
EXCO Resources:
EXCO Resources Credit Agreement	$	875.0	$	182.5	Current ratio	> 1.0	2.6
					Leverage ratio	< 4.5	3.3
Compass Production Partners:
Compass Production Partners Credit Agreement (3)	$	400.0	$	337.0	Current ratio	> 1.0	2.9
					Leverage ratio	< 4.5	3.4

(1) As defined in the respective credit agreements.

(2) Maximum leverage permitted or minimum coverage required per the respective credit agreement.

(3) Our proportionate share of Compass's outstanding indebtedness was $85.8 million as of June 30, 2014.

The 2018 Notes mature in September 2018 and have a fixed interest rate of 7.5%. The 2022 Notes mature in April 2022 and have a fixed interest rate of 8.5%. The indentures governing the 2018 Notes and 2022 Notes contain incurrence covenants which restrict our ability to incur additional indebtedness or pledge assets.

There are certain risks arising from volatility in oil and/or natural gas prices that could impact our ability to meet debt covenants in future periods. In particular, our leverage ratio, as defined in the EXCO Resources Credit Agreement, is computed using a trailing 12 month computation of EBITDAX and only includes operations from non-guarantor subsidiaries and unconsolidated joint ventures to the extent that cash is distributed to entities under the credit agreement. As a result, our ability to maintain compliance with this covenant is negatively impacted when oil and/or natural gas prices and/or production decline over an extended period of time.

Capital expenditures

For the six months endedJune 30, 2014, our capital expenditures totaled $199.2 million, of which $158.4 million was related to drilling and development activities. Our development program during the six months ended June 30, 2014 focused on our properties in the Haynesville and Eagle Ford shales. In the Haynesville shale, we operated three drilling rigs focused on our core area in DeSoto Parish, Louisiana and two drilling rigs focused on the Shelby area of East Texas. Our development program in the Eagle Ford shale focused on our core area in Zavala County, Texas and ranged from three to five operated drilling rigs during the six months ended June 30, 2014. Our development program in the Eagle Ford shale also included limited drilling outside our core area as part of a farmout agreement.

In June 2014, our board of directors approved an increase to our capital budget of up to $80.0 million for the remainder of the year. This allows us the flexibility to modify our drilling program in the Haynesville and Eagle Ford shales if opportunities arise to maximize our returns or further evaluate other formations. We continue to evaluate industry trends, commodity prices, and internal operational and financial analyses to assess potential modifications to our drilling program. We remain focused on efficiently managing our capital expenditures as part of our development program. We will incorporate any additional development into our hedging strategy and may enter into additional derivative contracts to protect our return on investment. The additional development as a result of our ability to increase our capital expenditures would not result in significant production volumes until 2015 based on the timing of wells turned-to-sales.

The following table presents our capital expenditures for the six months ended June 30, 2014. These capital expenditures exclude Compass, which funded its capital expenditures through internally generated cash flows and its credit agreement.

	Six Months Ended
(in thousands)	June 30, 2014
Capital expenditures:
Development capital expenditures	$	158,443
Field operations, gathering and water pipelines	17,965
Lease purchases	3,211
Seismic	158
Corporate and other	19,386
Total	$	199,163

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Capital commitments

During 2013, we entered into a participation agreement ("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. EXCO is required to offer to purchase our joint venture partner's working interest in wells drilled that have been on production for approximately one year. These offers will be made on a quarterly basis for groups of wells based on a price defined in the Participation Agreement, subject to specific well criteria and return hurdles. These acquisitions are expected to increase the borrowing base under the revolving commitment of the EXCO Resources Credit Agreement, and the acquisitions are expected to be funded with borrowings under the EXCO Resources Credit Agreement, cash flows from operations, or other financing arrangements.

As of June 30, 2014, we have spud 62 wells and turned-to-sales 29 wells since the inception of the Participation Agreement which are expected to be included within acquisitions in future periods. During the remainder of 2014, we expect to spud 23 wells which will be included in future acquisitions beginning in the fourth quarter of 2015. The timing of these acquisitions is dependent upon the date these wells are turned-to-sales and the downtime during the year preceding the offer process. Prior to the acquisitions in future periods, our average working interest in wells developed under this agreement is approximately 17% and our joint venture partner's average working interest is approximately 50%. The remaining working interest is held by other third-party owners and is not part of the acquisition program. Our average drilling and completion costs in the joint venture area are currently $6.8 million per well, of which our joint venture partner's share of these costs is approximately $3.4 million per well.

Historical sources and uses of funds

Our primary sources of cash for the six months ended June 30, 2014 were cash flows from operations and proceeds received from the Rights Offering, the issuance of the 2022 Notes and the sale of non-core assets. As a result of these sources of cash, we were able to significantly reduce our outstanding indebtedness under the EXCO Resources Credit Agreement.

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

	Six Months Ended June 30,
(in thousands)	2014			2013
Net cash provided by operating activities	$	268,122		$	171,232
Net cash provided by (used in) investing activities	(124,943		)	483,052
Net cash used in financing activities	(147,784		)	(619,486		)
Net increase (decrease) in cash	$	(4,605	)	$	34,798

Operating activities

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

For the six months ended June 30, 2014, our net cash provided by operating activities was $268.1 million as compared to $171.2 million for the six months ended June 30, 2013. The increase is primarily attributable to higher revenues from our recently acquired assets in the Haynesville and Eagle Ford shales as well as an increase in commodity prices. In addition, the increase was due to changes in Accounts payable and other current liabilities which provided cash of $68.8 million for the six months ended June 30, 2014 as compared to $2.7 million of cash provided by operating activities for the six months ended June 30, 2013. The increase in Accounts payable and other current liabilities was primarily due to advance billings to other working interest owners for our drilling and completion activities in the Eagle Ford shale. This increase was partially offset by cash payments of $34.5 million on derivative contracts for the six months ended June 30, 2014 compared to cash receipts of $17.5 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 producing properties and attractive acreage, acceptable rates of return, availability of borrowing capacity under the EXCO Resources Credit Agreement and availability of other sources of capital.

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For the six months ended June 30, 2014, our net cash used in investing activities was $124.9 million primarily due to drilling and development activities in the Haynesville and Eagle Ford shales. 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. For the six months ended June 30, 2013, our net cash provided by investing activities was $483.1 million primarily due to $574.8 million in proceeds as a result of the contribution of properties to Compass and the divestiture of certain properties for $37.9 million. This was partially offset by our proportionate share of Compass's acquisition of the shallow Cotton Valley assets from an affiliate of BG Group, plc ("BG Group").

Financing activities

For the six months ended June 30, 2014, our net cash used in financing activities was $147.8 million primarily due to $879.9 million in payments of outstanding indebtedness under the EXCO Resources Credit Agreement, $27.1 million of dividend payments and $10.1 million of deferred financing costs primarily related to issuance of the 2022 Notes. This was 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. For the six months ended June 30, 2013, our net cash used in financing activities was $619.5 million primarily due to $633.3 million in payments of outstanding indebtedness under the EXCO Resources Credit Agreement and $21.5 million of dividend payments. This was partially offset by the additional borrowings of Compass to fund the acquisition of shallow Cotton Valley assets from an affiliate of BG Group.

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 when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets. Our objective in entering into oil and natural gas derivative contracts is to mitigate the impact of commodity price fluctuations and achieve a more predictable cash flow associated with our operations. These transactions limit our exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase.                     

Our derivative financial instruments are comprised of oil and natural gas swaps, basis swaps and call option contracts. As of June 30, 2014, 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:
Q3 2014	21,185	$	4.22	414	$	95.03
Q4 2014	21,186	4.22		415	95.03
2015	28,287	4.31		976	93.19
Basis Swaps:
Q3 2014	—	—		46	6.03
Q4 2014	—	—		46	6.03
2015	—	—		91	6.10
Call options:
Q3 2014	5,060	4.29		92	100.00
Q4 2014	5,060	4.29		92	100.00
2015	20,075	4.29		365	100.00

We proportionately consolidate the derivative financial instruments entered into by Compass; however the contracts of Compass involve separate master netting agreements with their counterparties. As of June 30, 2014, our proportionate share of Compass's natural gas derivative swap contracts included approximately 2,811 Mmmbtu at an average price of $4.15 during 2014. Our proportionate share of Compass's oil derivative swap contracts included approximately 47 Mbbls at an average price of $91.87 during 2014 and approximately 64 Mbbls at an average price of $94.98 during 2015.

Compass had derivative financial instruments that covered approximately 68% and 69% of production volumes during the three and six months ended June 30, 2014, respectively. Excluding our proportionate share of Compass's derivative financial instruments, we had derivative financial instruments that covered approximately 67% of production volumes during both the three and six months ended June 30, 2014.

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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 June 30, 2014, we had no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments

There have been no material changes outside the ordinary course of business to our contractual obligations and commercial commitments since December 31, 2013.

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 charges 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 six months ended June 30, 2014, 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 $47.8 million. The ultimate settlement amount of our outstanding derivative financial instrument contracts is dependent on future commodity prices. We may incur significant unrealized losses in the future from our use of derivative financial instruments to the extent market prices increase and our derivatives contracts remain in place.

Interest rate risk

At June 30, 2014, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement and the Compass Production Partners Credit Agreement. The interest rate per annum on the 2018 Notes is fixed at 7.5% and the interest rate per annum on the 2022 Notes is fixed at 8.5%. Interest is payable on borrowings under the EXCO Resources Credit Agreement and Compass Production Partners 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 June 30, 2014, we had approximately $182.5 million in outstanding borrowings under the EXCO Resources Credit Agreement and $85.8 million of our proportionate share of outstanding borrowings under the Compass Production Partners Credit Agreement. A 1% change in interest rates (100 bps) based on the variable borrowings as of June 30, 2014 would result in an increase or decrease in our interest expense of approximately $2.7 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

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Item 4.     Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, EXCO's management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that EXCO's disclosure controls and procedures were effective as of June 30, 2014 to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms and (ii) accumulated and communicated to EXCO's management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There were no changes in EXCO's internal control over financial reporting that occurred during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, EXCO's internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer repurchases of common shares

The following table details our repurchase of common shares for the three months ended June 30, 2014:

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) (1)
April 1, 2014 - April 30, 2014	—	$	—	—	$	192.5
May 1, 2014 - May 31, 2014	—	—		—	192.5
June 1, 2014 - June 30, 2014	—	—		—	192.5
Total	—	$	—	—

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

Item 6. Exhibits

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

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SIGNATURES

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

		EXCO RESOURCES, INC.
		(Registrant)
Date:	July 30, 2014	/s/ Harold L. Hickey
		Harold L. Hickey
		President and Chief Operating Officer
		/s/ Mark F. Mulhern
		Mark F. Mulhern
		Executive Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Exhibit

Number Description of Exhibits

2.1 Unit Purchase and Contribution Agreement, dated November 5, 2012, by and among EXCO Resources, Inc., EXCO Operating Company, LP, EXCO/HGI JV Assets, LLC and HGI Energy Holdings, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 5, 2012 and filed on November 9, 2012 and incorporated by reference herein.

2.2 First Amendment to Unit Purchase and Contribution Agreement and Closing Agreement, dated as of February 14, 2013, by and among EXCO Resources, Inc., EXCO Operating Company, LP, EXCO/HGI JV Assets, LLC and HGI Energy Holdings, LLC, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.

2.3 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.

2.4 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.

2.5 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.

3.1 Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.

3.2 Articles of Amendment to the Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated August 30, 2007 and filed on September 5, 2007 and incorporated by reference herein.

3.3 Second Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated March 4, 2009 and filed on March 6, 2009 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 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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4.5 First Amended and Restated Registration Rights Agreement dates 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.

4.6 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.

4.7 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.

4.8 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.

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

4.10 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.

4.11 Fourth Supplemental Indenture, dated May 12, 2014, by and among EXCO Resources, Inc., EXCO Land Company, LLC and Wilmington Trust Company, as trustee, filed herewith.

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 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.*

10.6 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.*

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10.7 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.*

10.8 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 February 24, 2010 and incorporated by reference herein.*

10.9 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.*

10.10 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.

10.11 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.*

10.12 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.*

10.13 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.*

10.14 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.*

10.15 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.

10.16 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.

10.17 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.

10.18 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.

10.19 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.

10.20 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.

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10.21 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.

10.22 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.

10.23 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.

10.24 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.

10.25 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.

10.26 Amended and Restated Agreement of Limited Partnership of EXCO/HGI Production Partners, LP, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.

10.27 Form of Amended and Restated Limited Liability Company Agreement of EXCO/HGI GP, LLC, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.

10.28 Letter Agreement, dated November 5, 2012, by and among EXCO Resources, Inc., EXCO Operating Company, LP, Harbinger Group Inc. and HGI Energy Holdings, LLC, filed as an Exhibit to EXCO's Current Report on Form 8-K, dated November 5, 2012 and filed on November 9, 2012 and incorporated by reference herein.

10.29 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.*

10.30 Letter Agreement, dated March 1, 2013, by and between EXCO Resources, Inc. and Mark Mulhern, 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.*

10.31 EXCO Resources, Inc. 2013 Management Incentive Plan, 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.*

10.32 Credit Agreement, dated as of February 14, 2013, among EXCO/HGI JV Assets, LLC, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 2013 and incorporated by reference herein.

10.33 First Amendment to Credit Agreement, dated as of March 5, 2013, by and among EXCO/HGI JV Assets, LLC, as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO's Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2013 filed on May 1, 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.

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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.

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 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.

10.38 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 herewith.

10.39 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.

10.40 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.

10.41 Exercise Commitment Letter, dated November 22, 2013, by and among EXCO Resources, Inc., WLR Recovery Fund IV XCO AIV I, L.P., WLR Recovery Fund IV XCO AIV II, L.P., WLR Recovery Fund IV XCO AIV III, 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 November 22, 2013 and filed on November 25, 2013 and incorporated by reference herein.

10.42 Exercise Commitment Letter, dated November 22, 2013, by and among EXCO Resources, Inc. and Hamblin Watsa Investment Counsel Ltd, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 22, 2013 and filed on November 25, 2013 and incorporated by reference herein.

10.43 Investment Agreement, dated December 17, 2013, by and among WLR Recovery Fund IV XCO AIV I, L.P., WLR Recovery Fund IV XCO AIV II, L.P., WLR Recovery Fund IV XCO AIV III, L.P., WLR Select Co-Investment XCO AIV, L.P., WLR/GS Master Co-Investment XCO AIV, L.P., WLR IV Parallel ESC, L.P. and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Registration Statement on Form S-3 dated December 17, 2013 and filed on December 17, 2013 and incorporated by reference herein.

10.44 Investment Agreement, dated December 17, 2013, by and between Hamblin Watsa Investment Counsel Ltd., as representative of several investors, and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Registration Statement on Form S-3 dated December 17, 2013 and filed on December 17, 2013 and incorporated by reference herein.

10.45 Settlement Agreement and Mutual Release and Waiver of Claims, dated November 20, 2013, by and between EXCO Resources, Inc. and Douglas H. Miller, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 20, 2013 and filed on November 25, 2013 and incorporated by reference herein.*

10.46 Bonus and Retention Agreement, dated January 17, 2014, by and between William L. Boeing and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 24, 2014 and incorporated by reference herein.*

10.47 Bonus and Retention Agreement, dated January 17, 2014, by and between Harold L. Hickey and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 24, 2014 and incorporated by reference herein.*

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10.48 Bonus and Retention Agreement, dated January 17, 2014, by and between Mark F. Mulhern and EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 17, 2014 and filed on January 24, 2014 and incorporated by reference herein.*

10.49 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.

10.50 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.*

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

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

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

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Extension Schema Document.

101.CAL XBRL Taxonomy Calculation Linkbase Document.

101.DEF XBRL Taxonomy Definition Linkbase Document.

101.LAB XBRL Taxonomy Label Linkbase Document.

101.PRE XBRL Taxonomy Presentation Linkbase Document.

* These exhibits are management contracts.

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