Exco Resources (EXCO) 10-Q 2014 Q1 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 March 31, 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 April 24, 2014 was 272,763,909.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013	2
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013	4
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014 and 2013	5
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months Ended March 31, 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	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	40
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 6.	Exhibits	41
	Signatures	42

1

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	March 31, 2014			December 31, 2013
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	94,512		$	50,483
Restricted cash	16,943			20,570
Accounts receivable, net:
Oil and natural gas	147,868			128,352
Joint interest	36,707			70,759
Other	16,543			18,022
Derivative financial instruments	1,080			8,226
Inventory and other	7,699			9,442
Total current assets	321,352			305,854
Equity investments	56,924			57,562
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	392,595			425,307
Proved developed and undeveloped oil and natural gas properties	3,617,215			3,554,210
Accumulated depletion	(2,251,174		)	(2,183,464		)
Oil and natural gas properties, net	1,758,636			1,796,053
Gathering assets	33,605			33,473
Accumulated depreciation and amortization	(10,753		)	(10,338		)
Gathering assets, net	22,852			23,135
Office, field and other equipment, net	26,321			27,204
Deferred financing costs, net	27,242			28,807
Derivative financial instruments	6,007			6,829
Goodwill	163,155			163,155
Other assets	29			29
Total assets	$	2,382,518		$	2,408,628

See accompanying notes.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share and share data)	March 31, 2014			December 31, 2013
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	120,272		$	109,217
Revenues and royalties payable	185,744			154,862
Drilling advances	87,776			22,971
Accrued interest payable	3,241			18,144
Current portion of asset retirement obligations	191			191
Income taxes payable	—			—
Derivative financial instruments	31,547			11,919
Current maturities of long-term debt	—			31,866
Total current liabilities	428,771			349,170
Long-term debt	1,499,936			1,858,912
Deferred income taxes	—			—
Derivative financial instruments	5,283			9,671
Asset retirement obligations and other long-term liabilities	43,675			42,970
Commitments and contingencies	—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding	—			—
Common stock, $0.001 par value; 350,000,000 authorized shares; 273,317,397 shares issued and 272,778,176 shares outstanding at March 31, 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 March 31, 2014; 54,574,734 issued and outstanding at December 31, 2013	—			55
Additional paid-in capital	3,494,941			3,219,748
Accumulated deficit	(3,082,879		)	(3,064,634		)
Treasury stock, at cost; 539,221 shares at March 31, 2014 and December 31, 2013	(7,479		)	(7,479		)
Total shareholders’ equity	404,853			147,905
Total liabilities and shareholders’ equity	$	2,382,518		$	2,408,628

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
(in thousands, except per share data)	2014			2013
Revenues:
Oil	$	52,330		$	8,334
Natural gas	144,023			126,796
Natural gas liquids	2,119			3,093
Total revenues	198,472			138,223
Costs and expenses:
Oil and natural gas operating costs	18,787			13,617
Production and ad valorem taxes	7,609			5,248
Gathering and transportation	24,613			24,476
Depletion, depreciation and amortization	69,275			41,308
Impairment of oil and natural gas properties	—			10,707
Accretion of discount on asset retirement obligations	681			690
General and administrative	17,338			17,984
(Gain) loss on divestitures and other operating items	2,746			(184,882		)
Total costs and expenses	141,049			(70,852		)
Operating income	57,423			209,075
Other income (expense):
Interest expense, net	(20,164		)	(20,192		)
Loss on derivative financial instruments	(43,022		)	(43,514		)
Other income	46			88
Equity income	1,111			12,663
Total other expense	(62,029		)	(50,955		)
Income (loss) before income taxes	(4,606		)	158,120
Income tax expense	—			—
Net income (loss)	$	(4,606	)	$	158,120
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(0.02	)	$	0.74
Weighted average common shares outstanding	260,716			214,784
Diluted:
Net income (loss)	$	(0.02	)	$	0.74
Weighted average common shares and common share equivalents outstanding	260,716			214,861

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(in thousands)	2014			2013
Operating Activities:
Net income (loss)	$	(4,606	)	$	158,120
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	69,275			41,308
Share-based compensation expense	1,507			1,735
Accretion of discount on asset retirement obligations	681			690
Impairment of oil and natural gas properties	—			10,707
Income from equity investments	(1,111		)	(12,663		)
Loss on derivative financial instruments	43,022			43,514
Cash settlements (payments) of derivative financial instruments	(19,810		)	16,718
Amortization of deferred financing costs and discount on debt issuance	2,444			5,113
Gain on divestitures and other non-operating items	—			(187,038		)
Effect of changes in:
Accounts receivable	14,576			8,518
Other current assets	(2,517		)	(1,628		)
Accounts payable and other current liabilities	96,873			(41,880		)
Net cash provided by operating activities	200,334			43,214
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(101,404		)	(72,911		)
Property acquisitions	(426		)	(33,390		)
Proceeds from disposition of property and equipment	76,259			611,203
Restricted cash	3,627			16,793
Net changes in advances to joint ventures	(3,549		)	3,633
Equity method investments	1,749			(68		)
Net cash provided by (used in) investing activities	(23,744		)	525,260
Financing Activities:
Borrowings under credit agreements	—			46,757
Repayments under credit agreements	(391,174		)	(623,266		)
Proceeds from issuance of common stock	272,139			22
Payment of common stock dividends	(13,521		)	(10,739		)
Deferred financing costs and other	(5		)	(246		)
Net cash used in financing activities	(132,561		)	(587,472		)
Net increase (decrease) in cash	44,029			(18,998		)
Cash at beginning of period	50,483			45,644
Cash at end of period	$	94,512		$	26,646
Supplemental Cash Flow Information:
Cash interest payments	$	37,113		$	33,624
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	$	1,485		$	1,527
Capitalized interest	4,790			5,079
Issuance of common stock for director services	69			13
Accrued restricted stock dividends	118			127
Debt assumed upon formation of EXCO/HGI Partnership, 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	3		—		—		—			—		—			35		—			35
Share-based compensation	—		—		—		—			—		—			3,262		—			3,262
Restricted stock issued, net of cancellations	(80	)	—		—		—			—		—			—		—			—
Common stock dividends	—		—		—		—			—		—			—		(10,866		)	(10,866		)
Net income	—		—		—		—			—		—			—		158,120			158,120
Balance at March 31, 2013	218,049		$	215	—		$	—		(539	)	$	(7,479	)	$	3,203,364	$	(2,896,156	)	$	299,944
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	54,577		55		(54,575	)	(55		)	—		—			272,208		—			272,208
Share-based compensation	—		—		—		—			—		—			2,985		—			2,985
Restricted stock issued, net of cancellations	(43	)	—		—		—			—		—			—		—			—
Common stock dividends	—		—		—		—			—		—			—		(13,639		)	(13,639		)
Net loss	—		—		—		—			—		—			—		(4,606		)	(4,606		)
Balance at March 31, 2014	273,317		$	270	—		$	—		539		$	(7,479	)	$	3,494,941	$	(3,082,879	)	$	404,853

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 the EXCO/HGI Partnership.

•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 our Eagle Ford shale assets in South Texas. The South Texas region also includes assets in the Pearsall shale and the Austin Chalk and Buda 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 producing assets and Marcellus shale properties 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.

•EXCO/HGI Partnership

A joint venture with Harbinger Group Inc. ("HGI") in which we own a 25.5% economic interest in conventional shallow producing assets in East Texas and North Louisiana and shallow Canyon Sand and other assets in the Permian Basin ("EXCO/HGI Partnership"). We report our interest in the EXCO/HGI Partnership using proportional consolidation.

The accompanying Condensed Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013, Condensed Consolidated Statements of Operations, Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three months ended March 31, 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 present fairly the consolidated financial position of EXCO at March 31, 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.

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 EXCO's Annual Report on Form 10-K for the year ended December 31, 2013, filed with the SEC on February 26, 2014.

Recent accounting pronouncements

In February 2013, the Financial Accounting Standards Board ("FASB"), issued Accounting Standards Update, or 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"). The update 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. The update 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. The update 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 this update.

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 three months ended March 31, 2014:

(in thousands)
Asset retirement obligations at beginning of period	$	42,954
Activity during the period:
Liabilities incurred during the period	181
Liabilities settled during the period	(7		)
Adjustment to liability due to divestitures	(9		)
Accretion of discount	681
Asset retirement obligations at end of period	43,800
Less current portion	191
Long-term portion	$	43,609

Our asset retirement obligations are determined using discounted cash flow methodologies based on inputs that are not readily available in public markets. We have no 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 require 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 $392.6 million and $425.3 million as of March 31, 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. Our undeveloped properties are predominantly 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 three months ended March 31, 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, 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.

9

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 March 31, 2014, the trailing 12 month reference prices were $3.99 per Mmbtu for natural gas at Henry Hub, and $98.30 per Bbl of oil for West Texas Intermediate at Cushing, Oklahoma. The price used for NGLs was $42.78 per Bbl and was based on the trailing 12 month average of realized prices. Each of the reference prices for oil, natural gas and NGLs 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 months ended March 31, 2014 and we recognized a $10.7 million impairment to our proved oil and natural gas properties for the three months ended March 31, 2013.

6.Earnings per share

The following table presents the basic and diluted earnings (loss) per share computations for the three months ended March 31, 2014 and 2013: 

	Three Months Ended March 31,
(in thousands, except per share data)	2014			2013
Basic net income (loss) per common share:
Net income (loss)	$	(4,606	)	$	158,120
Weighted average common shares outstanding	260,716			214,784
Net income (loss) per basic common share	$	(0.02	)	$	0.74
Diluted net income (loss) per common share:
Net income (loss)	$	(4,606	)	$	158,120
Weighted average common shares outstanding	260,716			214,784
Dilutive effect of:
Stock options	—			5
Restricted shares	—			72
Weighted average common shares and common share equivalents outstanding	260,716			214,861
Net income (loss) per diluted common share	$	(0.02	)	$	0.74

Diluted earnings per share for the three months ended March 31, 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 14,120,734 and 16,582,021 antidilutive common share equivalents for the three months ended March 31, 2014 and 2013, respectively. The antidilutive common share equivalents primarily consisted of out-of-the-money stock options for the three months ended March 31, 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 in our Condensed Consolidated Statements of Operations.    

Fair Value of Derivative Financial Instruments

(in thousands)	March 31, 2014			December 31, 2013
Derivative financial instruments - Current assets	$	1,080		$	8,226
Derivative financial instruments - Long-term assets	6,007			6,829
Derivative financial instruments - Current liabilities	(31,547		)	(11,919		)
Derivative financial instruments - Long-term liabilities	(5,283		)	(9,671		)
Net derivative financial instruments	$	(29,743	)	$	(6,535	)

Effect of Derivative Financial Instruments

	Three Months Ended March 31,
(in thousands)	2014			2013
Loss on derivative financial instruments	$	(43,022	)	$	(43,514	)

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 West Texas Intermediate oil prices ("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 our counterparties on 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 the EXCO/HGI Partnership; however the contracts of the EXCO/HGI Partnership involve separate master netting agreements with their 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 the EXCO/HGI Partnership's derivative financial instruments) as of March 31, 2014:

(in thousands, except prices)	Volume Mmbtu/Bbl	Weighted average strike price per Mmbtu/Bbl		Fair value at March 31, 2014
Natural gas:
Swaps:
Remainder of 2014	63,325	$	4.22	(14,967		)
2015	28,287	4.31		3,203
Call options:
Remainder of 2014	15,125	4.29		(5,668		)
2015	20,075	4.29		(7,477		)
Total natural gas				$	(24,909	)
Oil:
Swaps:
Remainder of 2014	1,239	$	95.03	(3,724		)
2015	547	91.78		59
Basis swaps:
Remainder of 2014	138	6.03		384
2015	91	6.10		229
Calls options:
Remainder of 2014	275	100.00		(846		)
2015	365	100.00		(936		)
Total oil				$	(4,834	)
Total oil and natural gas derivative financial instruments				$	(29,743	)

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 March 31, 2014, the average forward NYMEX WTI oil prices per Bbl for the remainder of 2014 and calendar year 2015 were $98.47, and $90.69, respectively, the average forward NYMEX Louisiana Light Sweet ("LLS") oil prices per barrel for the remainder of 2014 and calendar year 2015 were $101.67, and $94.24, respectively, and the average forward NYMEX Henry Hub natural gas prices per Mmbtu for the remainder of 2014 and calendar year 2015 were $4.45 and $4.20, respectively.

As of March 31, 2014, our proportionate share of the EXCO/HGI Partnership's derivative swap contracts covered 4,200 Mmmbtu of natural gas and 70 Mbbls of oil for the remainder of 2014.

Our derivative financial instruments covered approximately 67% and 46% of production volumes for the three months ended March 31, 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.

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

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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 three months ended March 31, 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 March 31, 2014 and December 31, 2013.

	March 31, 2014
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	(29,743	)	$	—	$	(29,743	)
	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 the 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 the EXCO/HGI Partnership. 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 the EXCO/HGI Partnership 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 estimated 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 Henry Hub ("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.

The carrying values of our borrowings under the revolving commitment of the EXCO Resources Credit Agreement and EXCO/HGI Partnership 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.

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The estimated fair values of our 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and the term loan under the EXCO Resources Credit Agreement ("Term Loan"), at March 31, 2014 and December 31, 2013 are presented below. The estimated fair values of the 2018 Notes and the Term Loan have been calculated based on market quotes.

	March 31, 2014
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	756,653	$	—	$	—	$	756,653
Term Loan	298,867		—		—		298,867
	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)	March 31, 2014			December 31, 2013
Revolving commitment under EXCO Resources Credit Agreement	$	375,992		$	763,866
Term Loan under EXCO Resources Credit Agreement	297,750			298,500
Unamortized discount on Term Loan	(2,630		)	(2,780		)
2018 Notes	750,000			750,000
Unamortized discount on 2018 Notes	(6,968		)	(7,293		)
Total debt excluding the EXCO/HGI Partnership	1,414,144			1,802,293
EXCO/HGI Partnership Credit Agreement	85,792			88,485
Total debt	1,499,936			1,890,778
Less amounts due within one year	—			31,866
Total debt due after one year	$	1,499,936		$	1,858,912

Terms and conditions of each of these debt obligations are discussed below.

EXCO Resources Credit Agreement

As of March 31, 2014, we had $673.7 million of outstanding indebtedness under the EXCO Resources Credit Agreement including the revolving commitment and the Term Loan. The revolving commitment had an available borrowing base of approximately $900.0 million, with $376.0 million of outstanding indebtedness and $517.1 million of unused borrowing base, net of letters of credit. The maturity date of the revolving commitment 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 proceeds of $272.9 million which we used to pay down outstanding indebtedness under the EXCO Resources Credit Agreement, which included the remainder of the asset sale requirement as well as a portion of the revolving commitment. See further discussion in "Note 13. Rights Offering". Upon repayment of the asset sale requirement, the interest rate on the revolving commitment decreased by 100 basis points.

As of March 31, 2014, $297.8 million in principal was outstanding on the Term Loan. The unamortized discount on the Term Loan at March 31, 2014 was $2.6 million. On April 16, 2014, we closed an offering of $500.0 million in aggregate principal amount of senior unsecured notes (“2022 Notes") and subsequently utilized the proceeds to fully repay the Term Loan and the remaining proceeds were used to reduce the outstanding borrowings under the revolving commitment under the EXCO Resources Credit Agreement. See further discussion of our 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 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

14

bps), depending on our borrowing base usage. The interest rate grid was increased by 100 bps per annum until the asset sale requirement was eliminated in January 2014. On March 31, 2014, the one month LIBOR was 0.2%, which resulted in an interest rate of approximately 2.4% on the revolving commitment. The Term Loan accrued interest at LIBOR, with a floor of 100 bps, plus 400 bps (or ABR plus 300 bps). The interest rate on the Term Loan was approximately 5.0% as of March 31, 2014.

Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the engineered value, as defined in the agreement, in our oil and natural gas properties covered by the borrowing base. We are permitted to have derivative financial instruments covering no more than 100% of forecasted production from total proved reserves, as defined in the agreement, for any month during the first two years of the forthcoming five-year period, 90% of forecasted production from total proved reserves for any month during the third year of the forthcoming five-year period and 85% of forecasted production from total proved reserves for any month during the fourth and fifth years of the forthcoming five-year period.

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 and provides that we may declare and pay cash dividends on our common stock in an amount not to exceed a cumulative total of $50.0 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 March 31, 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 into 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. In particular, our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) is computed using the trailing 12 month 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 may be negatively impacted when 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 including our jointly-held equity investments with BG Group and the EXCO/HGI Partnership. Our equity investments with BG Group, other than OPCO, have been designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.

As of March 31, 2014, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at March 31, 2014 was $7.0 million. Interest accrues at 7.5% 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;

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• transfer or issue shares of stock of subsidiaries;

• transfer or sell assets; and

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

2022 Notes

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 year, 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 of the 2022 Notes offering to repay the $297.8 million outstanding principal balance on the Term Loan and the remaining proceeds were used to repay a portion of the outstanding balance of the revolving commitment under the EXCO Resources Credit Agreement.

The 2022 Notes rank equally in right of payment to any existing and future senior 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 indenture governing the 2022 Notes contains covenants that are generally similar to those with respect to the 2018 Notes.

EXCO/HGI Partnership Credit Agreement

As of March 31, 2014, the EXCO/HGI Partnership Credit Agreement had a borrowing base of $400.0 million. The borrowing base is redetermined semi-annually, with the EXCO/HGI Partnership and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. The EXCO/HGI Partnership Credit Agreement matures on February 14, 2018.

Borrowings under the EXCO/HGI Partnership Credit Agreement are secured by properties owned by the EXCO/HGI Partnership and we do not guarantee the EXCO/HGI Partnership's debt. The EXCO/HGI Partnership is not a guarantor of the EXCO Resources Credit Agreement, the 2018 Notes or the 2022 Notes. As of March 31, 2014, $337.0 million was drawn under the EXCO/HGI Partnership 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 March 31, 2014, the interest rate on the outstanding borrowings was approximately 2.7%.

Borrowings under the EXCO/HGI Partnership Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the engineered value, as defined in the EXCO/HGI Partnership Credit Agreement, of the oil and natural gas properties evaluated by the lenders for purposes of establishing the borrowing base. The EXCO/HGI Partnership is permitted to have derivative financial instruments covering no more than 100% of the forecasted production from proved developed producing reserves (as defined in the agreement) for any month during the first two years of the forthcoming five year period, 90% of the forecasted production from proved developed producing reserves for any month during the third year of the forthcoming five-year period and 85% of the forecasted production from proved developed producing reserves for any month during the fourth and fifth years of the forthcoming five-year period.

As of March 31, 2014, the EXCO/HGI Partnership was in compliance with the financial covenants contained in the EXCO/HGI Partnership Credit Agreement, which require that it:

• maintain a consolidated current ratio (as defined in the EXCO/HGI Partnership 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 (as defined in the EXCO/HGI Partnership Credit Agreement) to consolidated EBITDAX (as defined in the 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, the indenture governing the 2022 Notes and the EXCO/HGI Partnership Credit Agreement.

10.    Dividends

On March 10, 2014, our board of directors approved a cash dividend of $0.05 per share for the first quarter of 2014. The total cash dividend was $13.6 million, of which $13.5 million was paid on March 31, 2014 to holders of record on March 20, 2014 and the remainder was accrued to be paid to holders of restricted shares upon vesting.

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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 ceiling test write-downs to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Our valuation allowances increased $0.2 million for the three months ended March 31, 2014. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $891.8 million as of March 31, 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 allowance does not impact future utilization of the underlying tax attributes.

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. We did not advance any funds to OPCO for the three months ended March 31, 2014, and advanced $17.4 million for the three months ended March 31, 2013. There are service agreements between us and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the three months ended March 31, 2014 and 2013, we were reimbursed $9.7 million and $10.0 million, respectively, for administrative and technical services. As of March 31, 2014 and December 31, 2013, amounts due from OPCO to EXCO were $3.5 million and $2.3 million, respectively. As of March 31, 2014, amounts due from EXCO to OPCO were $1.2 million. EXCO did not owe any amounts to OPCO as of December 31, 2013. Advances to OPCO are recorded in "Other current assets" on our Condensed 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 Condensed 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. Wilbur L. Ross, Jr., the Chairman and Chief Executive Officer at WL Ross & Co. LLC, 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

On December 19, 2013, the Company granted subscription rights to holders of common stock which entitled the holder to purchase 0.25 of a share of our common stock for each share of common stock owned by such holders. Each subscription right entitled the holder to a basic subscription right and an over-subscription privilege. The basic subscription right entitled the holder to purchase 0.25 of a share of the Company’s common stock at a subscription price equal to $5.00 per share of common stock. The over-subscription privilege entitled the holders who exercised their basic subscription rights in full (including in respect of subscription rights purchased from others) to purchase any or all shares of common stock that other rights holders do not purchase through the purchase of their basic subscription rights at a subscription price equal to $5.00 per share of common stock. The subscription rights expired if they were not exercised by January 9, 2014.

The Company entered into two investment agreements ("Investment Agreements") in connection with the Rights Offering, each dated as of December 17, 2013, one with certain affiliates of WL Ross and one with Hamblin Watsa pursuant to which, subject to the terms and conditions thereof, each of them has 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 pro rata allocation among the subscription rights holders who have elected to exercise their over-subscription privilege.

The Rights Offering and related transactions under the Investment Agreements closed on January 17, 2014 and resulted in the issuance of 54,574,734 shares for proceeds of $272.9 million. We used the proceeds to pay indebtedness under the EXCO Resources Credit Agreement which is further discussed in "Note 9. Debt". 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.

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14. Condensed consolidating financial statements

As of March 31, 2014, the majority of EXCO’s subsidiaries were guarantors under the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes. All of our non-guarantor subsidiaries were considered unrestricted subsidiaries under the indenture governing the 2018 Notes, with the exception of our equity investment in OPCO. As of and for the three months ended March 31, 2014, our equity method investment in OPCO represented $11.8 million of equity method investments and contributed $1.1 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 the 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 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)

March 31, 2014

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	115,652		$	(27,680	)	$	6,540		$	—		$	94,512
Restricted cash	—			16,943			—			—			16,943
Other current assets	13,507			190,488			5,902			—			209,897
Total current assets	129,159			179,751			12,442			—			321,352
Equity investments	—			—			56,924			—			56,924
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	—			389,598			2,997			—			392,595
Proved developed and undeveloped oil and natural gas properties	330,503			3,166,572			120,140			—			3,617,215
Accumulated depletion	(330,503		)	(1,903,624		)	(17,047		)	—			(2,251,174		)
Oil and natural gas properties, net	—			1,652,546			106,090			—			1,758,636
Gathering, office, field and other equipment, net	2,941			24,430			21,802			—			49,173
Investments in and advances to affiliates, net	1,694,191			—			—			(1,694,191		)	—
Deferred financing costs, net	26,271			—			971			—			27,242
Derivative financial instruments	6,007			—			—			—			6,007
Goodwill	13,293			149,862			—			—			163,155
Other assets	2			27			—			—			29
Total assets	$	1,871,864		$	2,006,616		$	198,229		$	(1,694,191	)	$	2,382,518
Liabilities and shareholders' equity
Current liabilities	$	47,259		$	370,049		$	11,463		$	—		$	428,771
Long-term debt	1,414,144			—			85,792			—			1,499,936
Deferred income taxes	—			—			—			—			—
Other long-term liabilities	5,608			34,539			8,811			—			48,958
Payable to parent	—			2,037,160			35,012			(2,072,172		)	—
Total shareholders' equity	404,853			(435,132		)	57,151			377,981			404,853
Total liabilities and shareholders' equity	$	1,871,864		$	2,006,616		$	198,229		$	(1,694,191	)	$	2,382,518

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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 March 31, 2014

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	2,990		$	182,061		$	13,421		$	—		$	198,472
Costs and expenses:
Oil and natural gas production	299			21,421			4,676			—			26,396
Gathering and transportation	—			23,449			1,164			—			24,613
Depletion, depreciation and amortization	1,157			63,667			4,451			—			69,275
Impairment of oil and natural gas properties	—			—			—			—			—
Accretion of discount on asset retirement obligations	5			510			166			—			681
General and administrative	(235		)	16,846			727			—			17,338
Other operating items	(4		)	2,754			(4		)	—			2,746
Total costs and expenses	1,222			128,647			11,180			—			141,049
Operating income	1,768			53,414			2,241			—			57,423
Other income (expense):
Interest expense, net	(19,495		)	—			(669		)	—			(20,164		)
Loss on derivative financial instruments	(40,679		)	—			(2,343		)	—			(43,022		)
Other income (loss)	93			(51		)	4			—			46
Equity income	—			—			1,111			—			1,111
Net income from consolidated subsidiaries	53,707			—			—			(53,707		)	—
Total other expense	(6,374		)	(51		)	(1,897		)	(53,707		)	(62,029		)
Income (loss) before income taxes	(4,606		)	53,363			344			(53,707		)	(4,606		)
Income tax expense	—			—			—			—			—
Net income (loss)	$	(4,606	)	$	53,363		$	344		$	(53,707	)	$	(4,606	)

21

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2013

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	8,046		$	124,474		$	5,703		$	—		$	138,223
Costs and expenses:
Oil and natural gas production	2,212			14,105			2,548			—			18,865
Gathering and transportation	—			24,007			469			—			24,476
Depletion, depreciation and amortization	2,607			37,528			1,173			—			41,308
Impairment of oil and natural gas properties	—			10,707			—			—			10,707
Accretion of discount on asset retirement obligations	50			549			91			—			690
General and administrative	653			16,963			368			—			17,984
Other operating items	(25,974		)	(158,904		)	(4		)	—			(184,882		)
Total costs and expenses	(20,452		)	(55,045		)	4,645			—			(70,852		)
Operating income	28,498			179,519			1,058			—			209,075
Other income (expense):
Interest expense, net	(19,877		)	—			(315		)	—			(20,192		)
Loss on derivative financial instruments	(39,802		)	(690		)	(3,022		)	—			(43,514		)
Other income	47			39			2			—			88
Equity income	—			—			12,663			—			12,663
Net income from consolidated subsidiaries	189,254			—			—			(189,254		)	—
Total other income (expense)	129,622			(651		)	9,328			(189,254		)	(50,955		)
Income before income taxes	158,120			178,868			10,386			(189,254		)	158,120
Income tax expense	—			—			—			—			—
Net income	$	158,120		$	178,868		$	10,386		$	(189,254	)	$	158,120

22

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2014

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(51,192	)	$	244,986		$	6,540		$	—		$	200,334
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(747		)	(99,863		)	(1,220		)	—			(101,830		)
Proceeds from disposition of property and equipment	68,242			8,017			—			—			76,259
Restricted cash	—			3,627			—			—			3,627
Net changes in advances to joint ventures	—			(3,549		)	—			—			(3,549		)
Equity method investments	—			1,749			—			—			1,749
Distributions received from EXCO/HGI Partnership	765			—			—			(765		)	—
Advances/investments with affiliates	146,755			(146,755		)	—			—			—
Net cash provided by (used in) investing activities	215,015			(236,774		)	(1,220		)	(765		)	(23,744		)
Financing Activities:
Borrowings under credit agreements	—			—			—			—			—
Repayments under credit agreements	(388,624		)	—			(2,550		)	—			(391,174		)
Proceeds from issuance of common stock	272,139			—			—			—			272,139
Payment of common stock dividends	(13,521		)	—			—			—			(13,521		)
EXCO/HGI Partnership cash distribution	—			—			(765		)	765			—
Deferred financing costs and other	(5		)	—			—			—			(5		)
Net cash provided by (used in) financing activities	(130,011		)	—			(3,315		)	765			(132,561		)
Net increase in cash	33,812			8,212			2,005			—			44,029
Cash at beginning of period	81,840			(35,892		)	4,535			—			50,483
Cash at end of period	$	115,652		$	(27,680	)	$	6,540		$	—		$	94,512

23

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2013

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	(7,339	)	$	49,254		$	1,299		$	—	$	43,214
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment and property acquisitions	(5,567		)	(66,701		)	(34,033		)	—		(106,301		)
Restricted cash	—			16,793			—			—		16,793
Equity method investments	—			(68		)	—			—		(68		)
Proceeds from disposition of property and equipment	244,609			366,594			—			—		611,203
Net changes in advances to joint ventures	—			3,633			—			—		3,633
Advances/investments with affiliates	361,935			(361,935		)	—			—		—
Net cash provided by (used in) investing activities	600,977			(41,684		)	(34,033		)	—		525,260
Financing Activities:
Borrowings under credit agreements	10,000			—			36,757			—		46,757
Repayments under credit agreements	(623,266		)	—			—			—		(623,266		)
Proceeds from issuance of common stock	22			—			—			—		22
Payment of common stock dividends	(10,739		)	—			—			—		(10,739		)
Deferred financing costs and other	(31		)	—			(215		)	—		(246		)
Net cash provided by (used in) financing activities	(624,014		)	—			36,542			—		(587,472		)
Net increase (decrease) in cash	(30,376		)	7,570			3,808			—		(18,998		)
Cash at beginning of period	65,791			(20,147		)	—			—		45,644
Cash at end of period	$	35,415		$	(12,577	)	$	3,808		$	—	$	26,646

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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, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the 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,” "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 foreign 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, primarily related to our activities in shale formations, including the Eagle Ford shale play in South Texas;

• 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 for drilling and hydraulic fracturing 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;

25

• fluctuations in interest rates; and

• 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

The Company 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 net proceeds of $272.9 million. In connection with the Rights Offering, the Company entered into investment agreements ("Investment Agreements") with certain affiliates of WL Ross and 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 pay indebtedness under our credit agreement ("EXCO Resources Credit Agreement") including the remaining indebtedness related to 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 repay indebtedness under the EXCO Resources Credit Agreement.

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 year, payable in arrears on April 15 and October 15 of each year, with

26

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 indebtedness outstanding under the revolving commitment. 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 were 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.

27

Our results of operations

A summary of key financial data for the three months ended March 31, 2014 and 2013 related to our results of operations is presented below:

	Three Months Ended March 31,						Quarter to quarter change
(dollars in thousands, except per unit prices)	2014			2013
Production:
Oil (Mbbls)	593			102			491
Natural gas (Mmcf)	32,722			39,593			(6,871		)
Natural gas liquids (Mbbls)	59			82			(23		)
Total production (Mmcfe) (1)	36,634			40,697			(4,063		)
Average daily production (Mmcfe)	407			452			(45		)
Revenues before derivative financial instrument activities:
Oil	$	52,330		$	8,334		$	43,996
Natural gas	144,023			126,796			17,227
Natural gas liquids	2,119			3,093			(974		)
Total revenues	$	198,472		$	138,223		$	60,249
Oil and natural gas derivative financial instruments:
Loss on derivative financial instruments	$	(43,022	)	$	(43,514	)	$	492
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	88.25		$	81.71		$	6.54
Natural gas (per Mcf)	4.40			3.20			1.20
Natural gas liquids (per Bbl)	35.92			37.72			(1.80		)
Natural gas equivalent (per Mcfe)	5.42			3.40			2.02
Costs and expenses:
Oil and natural gas operating costs	$	18,787		$	13,617		$	5,170
Production and ad valorem taxes	7,609			5,248			2,361
Gathering and transportation	24,613			24,476			137
Depletion	67,736			38,991			28,745
Depreciation and amortization	1,539			2,317			(778		)
General and administrative (2)	17,338			17,984			(646		)
Interest expense, net	20,164			20,192			(28		)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.51		$	0.33		$	0.18
Production and ad valorem taxes	0.21			0.13			0.08
Gathering and transportation	0.67			0.60			0.07
Depletion	1.85			0.96			0.89
Depreciation and amortization	0.04			0.06			(0.02		)
General and administrative	0.47			0.44			0.03
Net income (loss)	$	(4,606	)	$	158,120		$	(162,726	)

(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 $1.5 million and $1.7 millionfor the three months endedMarch 31, 2014 and 2013, respectively.

The following is a discussion of our financial condition and results of operations for the three months ended March 31, 2014 and 2013.

The comparability of our results of operations for March 31, 2014 and 2013 was affected by:

• the acquisitions of the Haynesville and Eagle Ford assets during the third quarter of 2013, including the debt refinancing to facilitate these acquisitions;

28

• the formation of the EXCO/HGI Partnership during the first quarter of 2013;

• the sale of our equity interest in 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 the amount of our debt.

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 endedMarch 31, 2014 and 2013, we reported a net loss of $4.6 million and net income of $158.1 million, respectively. The net loss for the three months ended March 31, 2014 included operating income of $57.4 million and was negatively impacted by realized and unrealized losses on derivative financial instruments resulting from increases in commodity prices. The net incomefor the three months endedMarch 31, 2013 was primarily the result of the gain on the divestiture of certain oil and natural gas properties in connection with the formation of the EXCO/HGI Partnership.

Average natural gas equivalent prices before the effects of derivative financial instruments were $5.42 per Mcfe for the three months ended March 31, 2014, compared with $3.40 per Mcfe for the three months endedMarch 31, 2013. This increase was due to higher natural gas prices as well as a higher proportion of our total production attributed to oil from the Eagle Ford shale.

We use oil and natural gas swap, basis swap and call option contracts to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow from our operations. Our oil and natural gas derivative financial instruments resulted in net losses of $43.0 million and $43.5 millionfor the three months ended March 31, 2014 and 2013, respectively.

Presentation of results of operations

Our discussion of production, revenues and direct operating expenses is based on our producing regions and the EXCO/HGI Partnership. The EXCO/HGI Partnership includes conventional non-shale assets in East Texas, North Louisiana and the Permian Basin. Prior to the formation of the EXCO/HGI Partnership 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 the EXCO/HGI Partnership represent our

29

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 table presents our production, revenue and average sales prices for the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
	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	25,230	$	115,797	$	4.59	33,449	$	106,787	$	3.19	(8,219	)	$	9,010		$	1.40
South Texas	3,504	44,818		12.79		—	—		—		3,504		44,818			12.79
Appalachia	5,496	21,448		3.90		5,066	17,687		3.49		430		3,761			0.41
Other	225	2,988		13.28		1,003	8,046		8.02		(778	)	(5,058		)	5.26
EXCO/HGI Partnership	2,179	13,421		6.16		1,179	5,703		4.84		1,000		7,718			1.32
Total	36,634	$	198,472	$	5.42	40,697	$	138,223	$	3.40	(4,063	)	$	60,249		$	2.02

Production for the three months endedMarch 31, 2014decreased by 4.1 Bcfe, or 10%, as compared with the same period in 2013. The decrease in production in the East Texas/North Louisiana region was primarily due to normal production declines resulting from our reduced drilling program and the contribution of properties to the EXCO/HGI Partnership of 3.1 Bcfe. Our drilling activities in the Haynesville shale resulted in two wells turned-to-sales for the three months endedMarch 31, 2014 compared to 19 wells turned-to-sales for the three months endedMarch 31, 2013. The variability in number of wells turned-to-sales compared to prior year was partially due to the timing of completion activities as a result of our multi-well pad design in which we drill all wells in the unit before beginning the completion phase. As of March 31, 2014, we had 10 wells in the Haynesville shale that were waiting on completion which are expected to be turned-to-sales during the second quarter of 2014. We acquired assets in the Eagle Ford shale on July 31, 2013 and formed our South Texas region. Our production in the South Texas region was 3.5 Bcfe for the three months endedMarch 31, 2014, which consisted of 525 Mbbls of oil, 17 Mbbls of natural gas liquids and 254 Mmcf of natural gas. We turned-to-sales 13 wells in the Eagle Ford shale during the three months ended March 31, 2014. The increase in production of 0.4 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 the EXCO/HGI Partnership. The increase in our proportionate share of the EXCO/HGI Partnership'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 three months endedMarch 31, 2014increased by $60.2 million, or 44%, 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 38% to $4.40 per Mcf for the three months endedMarch 31, 2014 from $3.20 per Mcf for the three months endedMarch 31, 2013. Our average sales price for natural gas during 2014 was positively impacted by higher demand due to lower than average temperatures during the winter season which resulted in significantly lower storage levels compared to recent historical averages. However, this was partially offset by the widening of differentials in Appalachia as a result of an oversupply in the Northeast region and lower prices received from our purchasers for natural gas production in the South Texas region due to higher deductions for gathering and transportation costs. Our average sales price of oil per Bbl increased 8% to $88.25 per Bbl for the three months endedMarch 31, 2014 from $81.71 per Bbl for the three months endedMarch 31, 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 5% to $35.92 per Bbl for the three months endedMarch 31, 2014 from $37.72 per Bbl for the three months endedMarch 31, 2013.

Oil and natural gas operating costs

The following tables present our operating costs for the three months ended March 31, 2014 and 2013:

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	Three Months Ended March 31,
	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	$	4,314	$	1,524	$	5,838	$	5,407	$	1,595	$	7,002	$	(1,093	)	$	(71	)	$	(1,164	)
South Texas	5,851		125		5,976		—		—		—		5,851			125			5,976
Appalachia	3,373		6		3,379		3,278		—		3,278		95			6			101
Other	154		—		154		1,460		—		1,460		(1,306		)	—			(1,306		)
EXCO/HGI Partnership	2,898		542		3,440		1,652		225		1,877		1,246			317			1,563
Total	$	16,590	$	2,197	$	18,787	$	11,797	$	1,820	$	13,617	$	4,793		$	377		$	5,170
	Three Months Ended March 31,
	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	$	0.17	$	0.06	$	0.23	$	0.16	$	0.05	$	0.21	$	0.01		$	0.01		$	0.02
South Texas	1.67		0.04		1.71		—		—		—		1.67			0.04			1.71
Appalachia	0.61		—		0.61		0.65		—		0.65		(0.04		)	—			(0.04		)
Other	0.68		—		0.68		1.46		—		1.46		(0.78		)	—			(0.78		)
EXCO/HGI Partnership	1.33		0.25		1.58		1.40		0.19		1.59		(0.07		)	0.06			(0.01		)
Total	$	0.45	$	0.06	$	0.51	$	0.29	$	0.04	$	0.33	$	0.16		$	0.02		$	0.18

Oil and natural gas operating costs for the three months endedMarch 31, 2014 increased by $5.2 million, or 38%, as compared with the same period in 2013. The increase in total 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 the EXCO/HGI Partnership.

As shown in the tables above, oil and natural gas operating costs for the three months endedMarch 31, 2014 were $0.51 per Mcfe compared to $0.33 per Mcfe for the three months ended March 31, 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. This was partially offset by the contribution of properties to the EXCO/HGI Partnership which typically have a higher cost per Mcfe compared to the average for the rest of our properties.

Gathering and transportation

Gathering and transportation expenses for the three months endedMarch 31, 2014 increased by $0.1 million, or 1%, as compared with the same period in 2013. Gathering and transportation expenses were $0.67 per Mcfe for the three months endedMarch 31, 2014, as compared to $0.60 per Mcfe for the three months endedMarch 31, 2013. In connection with the sale of our equity interest in TGGT during 2013, we assigned certain gathering and transportation contracts to the buyer and continue to use them as a midstream service provider in the East Texas/ North Louisiana region. The increase in gathering and transportation expense on a per Mcfe basis was primarily due to lower volumes in relation to fixed costs under firm transportation contracts. 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. In April 2014, a marketing arrangement with a significant purchaser of our Haynesville shale production volumes was revised and will result in higher gathering and transportation expenses in future periods.

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Production and ad valorem taxes

The following table presents our production and ad valorem taxes on a per Mcfe basis and percentage of revenue basis for the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
	2014						2013						Quarter to quarter change
(in thousands, except per unit rate)	Production and ad valorem taxes		% of revenue		Taxes $/Mcfe		Production and ad valorem taxes		% of revenue		Taxes $/Mcfe		Production and ad valorem taxes			Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	2,370	2.0	%	$	0.09	$	3,150	2.9	%	$	0.09	$	(780	)	$	—
South Texas	3,252		7.3	%	0.93		—		—	%	—		3,252			0.93
Appalachia	607		2.8	%	0.11		675		3.8	%	0.13		(68		)	(0.02		)
Other	145		4.9	%	0.64		752		9.3	%	0.75		(607		)	(0.11		)
EXCO/HGI Partnership	1,235		9.2	%	0.57		671		11.8	%	0.57		564			—
Total	$	7,609	3.8	%	$	0.21	$	5,248	3.8	%	$	0.13	$	2,361		$	0.08

Production and ad valorem taxes for the three months endedMarch 31, 2014 increased by $2.4 million, or 45%, as compared with the same period in 2013. The increase was primarily attributable to higher production and ad valorem taxes associated with our liquids production in the South Texas 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 $0.13 for the three months ended March 31, 2014 and 2013, respectively. The rate per Mcfe increased due to higher production and ad valorem taxes per Mcfe associated with our liquids production in the South Texas region.

In our East Texas/North Louisiana area, 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.

Depletion, depreciation and amortization

Depletion expense for the three months endedMarch 31, 2014 increased by $28.7 million, or 74%, as compared with the same period in 2013. On a per Mcfe basis, the depletion rate for the three months ended March 31, 2014 was $1.85 per Mcfe, compared with $0.96 per Mcfe in the same period in 2013. The increase in the depletion rate was primarily due to the acquisition of oil producing assets in the South Texas region and revisions of reserve quantities to our properties in the Haynesville shale.

Depreciation and amortization costs for the three months endedMarch 31, 2014decreased by $0.8 million, or 34%, as compared with the same period in 2013. The decrease was due to contribution of gathering assets to the EXCO/HGI Partnership.

Accretion of discount on asset retirement obligations for the three months endedMarch 31, 2014 was $0.7 millionfor the three months endedMarch 31, 2014 and 2013. The contribution of properties to the EXCO/HGI Partnership resulted in lower accretion, but this was offset by the accretion of discount on asset retirement obligations of Haynesville and Eagle Ford assets acquired during the third quarter of 2013.

Impairment of oil and natural gas properties

For the three months endedMarch 31, 2014, we did not record an impairment to our oil and natural gas properties. For the three months ended March 31, 2013, we recorded an impairment of $10.7 million to our oil and natural gas properties primarily due to low natural gas prices.

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General and administrative

The following table presents our general and administrative expenses for the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
(in thousands, except per unit rate)	2014			2013			Quarter to quarter change
General and administrative costs:
Gross general and administrative expense	$	31,052		$	32,131		$	(1,079	)
Technical services and service agreement charges	(6,005		)	(6,335		)	330
Operator overhead reimbursements	(3,353		)	(3,099		)	(254		)
Capitalized salaries and share-based compensation	(4,356		)	(4,713		)	357
General and administrative expense	$	17,338		$	17,984		$	(646	)
General and administrative expense per Mcfe	$	0.47		$	0.44		$	0.03

The decrease in general and administrative expense for the three months ended March 31, 2014 compared to 2013 was primarily a result of decreased personnel expenses of $1.4 million due to a reduction in employee headcount. The reduction in employee headcount was the result of the formation of the EXCO/HGI Partnership and the centralization of certain functions from the Appalachia region during 2013. In April 2014, we underwent a further reduction in our workforce as a result of our continued focus on fiscal discipline and managing our general and administrative costs. This was partially offset by lower capitalized salaries and an increase in miscellaneous expenses.

(Gain) loss on divestitures and other operating items

(Gain) loss on divestitures and other operating items was a net loss of $2.7 million for the three months ended March 31, 2014 compared with a net gain of $184.9 million for the three months ended March 31, 2013. The loss for the three months ended March 31, 2014 primarily consisted of expenses related to various litigation. The net gain for the three months ended March 31, 2013 was primarily related to the gain of $187.0 million as a result of the contribution of certain oil and natural gas properties to the EXCO/HGI Partnership. Partially offsetting the gain were expenses incurred in various litigation and losses related to equipment sales.

Interest expense, net

The following table presents our interest expense, net for the three months ended March 31, 2014 and 2013:

	Three Months Ended March 31,
(in thousands)	2014			2013			Quarter to quarter change
Interest expense, net:
2018 Notes	$	14,387		$	14,363		$	24
Revolving credit facility under EXCO Resources Credit Agreement	4,044			5,714			(1,670		)
Term Loan under EXCO Resources Credit Agreement	3,881			—			3,881
EXCO/HGI Partnership Credit Agreement	606			322			284
Amortization of deferred financing costs	1,971			4,813			(2,842		)
Capitalized interest	(4,790		)	(5,079		)	289
Other	65			59			6
Total interest expense, net	$	20,164		$	20,192		$	(28	)

Interest expense, net for the three months ended March 31, 2014 was consistent with the same period in 2013. The decrease in the amortization of deferred financing costs was primarily due to acceleration of costs during the three months ended March 31, 2013 associated with the reduction of our borrowing base as a result of the EXCO/HGI Partnership formation. This was partially offset by higher interest expense under the EXCO Resources Credit Agreement during the three months ended March 31, 2014 due to higher average outstanding indebtedness and a higher average interest rate as a result of the Term Loan. We expect our interest expense to increase in future periods as a result of the issuance of the 2022 Notes, which bear interest at a rate of 8.5% per annum.

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Derivative financial instruments

Our oil and natural gas derivative financial instruments resulted in net losses of $43.0 million and $43.5 million for the three months ended March 31, 2014 and 2013, respectively. The net losses during these periods were primarily the result of increases in natural gas futures index prices. Based on the nature of our derivative contracts, increases in the related commodity price typically result in a decrease to the value of our derivatives contracts. The significant fluctuations demonstrate the high volatility in oil and natural gas prices between each of the periods. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

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

	Three Months Ended March 31,
Average realized pricing:	2014			2013		Quarter to quarter change
Natural gas equivalent per Mcfe	$	5.42		$	3.40	$	2.02
Cash (payments) settlements on derivative financial instruments, per Mcfe	(0.54		)	0.41		(0.95		)
Net price per Mcfe, including derivative financial instruments	$	4.88		$	3.81	$	1.07

Our total cash payments for the three months ended March 31, 2014 were $19.8 million, or $0.54 per Mcfe, compared to cash receipts of $16.7 million, or $0.41 per Mcfe, for the three months ended March 31, 2013. As noted above, the significant fluctuations between settlements on our derivative financial instruments demonstrate the volatility in commodity prices.

Historically we have entered into oil and natural gas derivatives contracts to reduce our exposure to volatility in commodity prices in order to protect our cash flows to meet our debt service obligations. These transactions limit exposure to declines in commodity prices, but also limit the benefits of increases in commodity prices. Although we expect to continue our comprehensive derivative financial instrument program as part of our overall business strategy, the recent improvements to our liquidity allow us the flexibility to retain upside optionality for rising prices in future periods.

Equity income

Equity income decreased by $11.6 million from $12.7 million for the three months ended March 31, 2013 to $1.1 million for the three months ended March 31, 2014. The decrease was primarily due to the sale of our equity interest in TGGT on November 15, 2013, which accounted for $12.9 million of our equity income for the three months ended March 31, 2013.

Income taxes

Our effective income tax rate for the three months ended March 31, 2014 and 2013 was zero, primarily due to prior losses arising from ceiling test write-downs which created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our accumulated valuation allowance as of March 31, 2014 was approximately $891.8 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 5.1% and 45.8% for the three months ended March 31, 2014 and 2013, respectively.

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;

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

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

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

• potential acquisitions and/or 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

We closed the Rights Offering and related private placement on January 17, 2014 which resulted in the issuance of 54,574,734 shares of our common stock for net proceeds of $272.9 million. We used the net proceeds to pay indebtedness under the EXCO Resources Credit Agreement, including payment in full of the remaining indebtedness related to the asset sale requirement as well as a portion of the indebtedness outstanding under the revolving commitment. Upon repayment of the asset sale requirement, the interest rate on the revolving commitment decreased by 100 basis points. The repayment of indebtedness under asset sale requirement resulted in a corresponding reduction in our borrowing base.

On March 24, 2014, we sold a non-operated interest in certain assets in the Permian Basin for $68.2 million and utilized all of the proceeds to reduce indebtedness under the EXCO Resources Credit Agreement. Prior to the sale, these assets had not previously been included in the determination of the borrowing base under the EXCO Resources Credit Agreement. In addition, we utilized $46.8 million of cash flows from operations to further reduce our indebtedness under the EXCO Resources Credit Agreement during the three months ended March 31, 2014.

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 bear interest at a rate of 8.5% per year, 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 to repay the $297.8 million outstanding principal balance on the Term Loan and the remaining proceeds were used to reduce the outstanding borrowings of the revolving commitment under 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.

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 our results of operations.

The following table presents our liquidity as of March 31, 2014 as well as on a pro forma basis as if the 2022 Notes offering had occurred on March 31, 2014. The pro forma information is not considered to be complete and excludes the impact of all other transactions subsequent to March 31, 2014:

(in thousands)	March 31, 2014		Pro forma
Cash (1) (2)	$	104,915	$	104,915
Revolving credit facility under the EXCO Resources Credit Agreement	375,992		183,720
Term loan under the EXCO Resources Credit Agreement (3)	297,750		—
2018 Notes (4)	750,000		750,000
2022 Notes (5)	—		500,000
Total debt (6)	$	1,423,742	$	1,433,720
Net debt	$	1,318,827	$	1,328,805
Borrowing base (7)	$	1,200,000	$	875,000
Unused borrowing base (8)	$	517,120	$	684,392
Unused borrowing base plus cash (1) (8)	$	622,035	$	789,307

(1) Includes restricted cash of $16.9 million at March 31, 2014.

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(2) Excludes our proportionate share of cash related to the EXCO/HGI Partnership of $6.5 million at March 31, 2014.

(3) Excludes unamortized discount of $2.6 million at March 31, 2014.

(4) Excludes unamortized discount of $7.0 million at March 31, 2014.

(5) The net proceeds of approximately $490.0 million were utilized to reduce the remaining indebtedness under the Term Loan and a portion of the revolving commitment under the EXCO Resources Credit Agreement.

(6) Excludes our proportionate share of the debt related to the EXCO/HGI Partnership of $85.8 million as of March 31, 2014.

(7) Includes the borrowing base for the revolving commitment and Term Loan under the EXCO Resources Credit Agreement as of March 31, 2014. 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. This reduction in our borrowing base is presented on a pro forma basis within this table.

(8) Net of $6.9 million in letters of credit as of March 31, 2014.

Credit agreements and long-term debt

As of March 31, 2014, our consolidated debt consisted of the EXCO Resources Credit Agreement, the 2018 Notes and our 25.5% proportionate share of the EXCO/HGI Partnership 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 the EXCO/HGI Partnership's debt is consolidated, we are not a guarantor of the debt.

As of March 31, 2014, EXCO and the EXCO/HGI Partnership 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 EXCO/HGI Partnership Credit Agreement.

	March 31, 2014
(dollars in millions)	Borrowing base		Outstanding		Covenant type (2)	Required ratio (3)	Actual ratio
EXCO Resources:
EXCO Resources Credit Agreement (1)	$	1,200.0	$	673.7	Current ratio	> 1.0	2.1
					Leverage ratio	< 4.5	3.0
EXCO/HGI Partnership:
EXCO/HGI Partnership Credit Agreement (4)	$	400.0	$	337.0	Current ratio	> 1.0	2.9
					Leverage ratio	< 4.5	3.4

(1) The borrowing base presented within this table for the EXCO Resources Credit Agreement includes both the revolving commitment and the Term Loan.

(2) As defined in the respective credit agreements.

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

(4) The borrowing base and outstanding indebtedness presented within this table reflect the total EXCO/HGI Partnership. Our proportionate share of the EXCO/HGI Partnership's outstanding indebtedness was $85.8 million as of March 31, 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.

Furthermore, the increase in our indebtedness may limit our ability to pay dividends as a result of covenants within the EXCO Resources Credit Agreement which states that we may declare and pay cash dividends on our common stock in an amount not to exceed a cumulative total of $50.0 million in any four consecutive fiscal quarters, provided that, as of each

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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 or the 2022 Notes. As of March 31, 2014, we had approximately 58% of the revolving commitment available under the EXCO Resources Credit Agreement. After giving effect to the issuance of the 2022 Notes, we had approximately 79% of the revolving commitment available under the EXCO Resources Credit Agreement. As a result of the issuance of additional shares of our common stock in connection with the Rights Offering, we will be required to reduce our dividends in order to maintain compliance with the annual limitation of $50.0 million under the EXCO Resources Credit Agreement unless we are able to amend the related covenant as well as comply with the limitations in the indentures governing the 2018 and 2022 Notes.

Capital expenditures

Our 2014 capital budget is $368.0 million, of which $294.0 million is allocated to development and completion activities. Our capital program was designed to manage our capital expenditures in relation to our operating cash flow. For the three months endedMarch 31, 2014, our capital expenditures totaled $100.0 million, of which $80.2 million was related to drilling and development activities. Our development program during the three months ended March 31, 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 included four operated drilling rigs at the beginning of the period and increased to five operated drilling rigs as of March 31, 2014. We have focused on efficiently managing our capital expenditures as part of our development program. We continuously evaluate modifications to our drilling schedule in order to maximize our returns in reaction to commodity prices and industry trends.

The following table presents our capital expenditures for the three months ended March 31, 2014. Our capital program was structured to allocate a higher proportionate share of our expenditures on drilling activities during the first half of the year. These capital expenditures exclude the EXCO/HGI Partnership, which funded its capital expenditures through internally generated cash flows and its credit agreement.

	Three Months Ended March 31,
(in thousands)	2014
Capital expenditures:
Lease purchases	$	1,996
Development capital expenditures	80,198
Seismic	8
Field operations, gathering and water pipelines	8,518
Corporate and other	9,317
Total	$	100,037

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 alternative financing arrangements.

As of March 31, 2014, we have spud 44 wells and turned-to-sales 18 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 65 wells which will be included in future acquisitions beginning in the third 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

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costs in the joint venture area are currently $6.9 million per well, of which our joint venture partner's share of these costs is approximately $3.5 million per well.

Historical sources and uses of funds

Our primary sources of cash for the three months ended March 31, 2014 were cash flows from operations, proceeds received from the Rights Offering and proceeds from the sale of assets. As a result of these sources of cash, we were able to significantly reduce our outstanding borrowings under the EXCO Resources Credit Agreement.

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

	Three Months Ended March 31,
(in thousands)	2014			2013
Net cash provided by operating activities	$	200,334		$	43,214
Net cash provided by (used in) investing activities	(23,744		)	525,260
Net cash used in financing activities	(132,561		)	(587,472		)
Net increase (decrease) in cash	$	44,029		$	(18,998	)

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 three months ended March 31, 2014, our cash flows provided by operating activities were $200.3 million as compared to $43.2 million for the three months ended March 31, 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 $96.9 million for the three months ended March 31, 2014 as compared to $41.9 million of cash used in operating activities for the three months ended March 31, 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 approximately $36.5 million of lower settlements on our derivative contracts. We had cash payments of $19.8 million on derivative contracts for the three months ended March 31, 2014 compared to cash receipts of $16.7 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.

For the three months ended March 31, 2014, our cash flows used in investing activities were $23.7 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 three months ended March 31, 2013, our cash flows provided by investing activities were $525.3 million primarily due to $573.3 million in proceeds as a result of the contribution of properties to the EXCO/HGI Partnership and the divestiture of certain properties for $37.9 million. This was partially offset by our proportionate share of the EXCO/HGI Partnership's acquisition of the shallow Cotton Valley assets from an affiliate of BG Group.

Financing activities

For the three months ended March 31, 2014, our cash flows used in financing activities were $132.6 million primarily due to $388.6 million in repayments of the outstanding borrowings under the EXCO Resources Credit Agreement and $13.5 million of dividend payments. This was partially offset by approximately $272.9 million of net proceeds received from the Rights Offering. For the three months ended March 31, 2013 our cash flows used in financing activities were $587.5 million primarily due to $623.3 million repayments of the outstanding borrowings under the EXCO Resources Credit Agreement and $10.7 million of dividend payments. This was partially offset by the additional borrowings of the EXCO/HGI Partnership to fund the acquisition of shallow Cotton Valley assets from an affiliate of BG Group.

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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 March 31, 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:
Q2 2014	20,955	$	4.22	410	$	95.03
Q3 2014	21,185	4.22		414	95.03
Q4 2014	21,185	4.22		415	95.03
2015	28,287	4.31		547	91.78
Basis Swaps:
Q2 2014	—	—		46	6.03
Q3 2014	—	—		46	6.03
Q4 2014	—	—		46	6.03
2015	—	—		91	6.10
Call options:
Q2 2014	5,005	4.29		91	100.00
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 the EXCO/HGI Partnership. However, we are not liable in the event of default on the EXCO/HGI Partnership's derivative contracts. As of March 31, 2014, our proportionate share of the EXCO/HGI Partnership's natural gas derivative swap contracts included approximately 15,000 Mmbtu per day at an average price of $4.15 during 2014. Our proportionate share of the EXCO/HGI Partnership's oil derivative swap contracts included approximately 255 Bbls per day at an average price of $91.87 during 2014.

The EXCO/HGI Partnership had derivative financial instruments that covered approximately 69% of production volumes during the three months ended March 31, 2014. Excluding our proportionate share of the EXCO/HGI Partnership's derivative financial instruments, we had derivative financial instruments that covered approximately 67% of production volumes during the three months ended March 31, 2014.

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 March 31, 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.

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Item 3.     Quantitative and Qualitative Disclosures About Market Risk

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

Commodity price risk

Our objective in entering into derivative financial instruments is to manage our exposure to commodity price fluctuations, protect our returns on investments, and achieve a more predictable cash flow in connection with our financing activities and borrowings related to these activities. These transactions limit exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash 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. 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 three months ended March 31, 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 $24.6 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 March 31, 2014, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement and the EXCO/HGI Partnership 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 EXCO/HGI Partnership 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 March 31, 2014, we had approximately $673.7 million in outstanding borrowings under the EXCO Resources Credit Agreement, including the revolving commitment and the Term Loan, and $85.8 million for our proportionate share of outstanding borrowings under the EXCO/HGI Partnership Credit Agreement. A 1% change in interest rates (100 bps) based on the variable borrowings as of March 31, 2014 would result in an increase or decrease in our interest expense of approximately $4.7 million per year. After giving effect for the repayment of indebtedness under the Term Loan and revolving commitment of the EXCO Resources Credit Agreement with proceeds from the 2022 Notes, a 1% change in interest rates (100 bps) based on the variable borrowings 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.

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 March 31, 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.

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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 March 31, 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 March 31, 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)
January 1, 2014 - January 31, 2014	—	$	—	—	$	192.5
February 1, 2014 - February 28, 2014	—	—		—	192.5
March 1, 2014 - March 31, 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:	April 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.

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

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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.

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

10.6 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.*

10.7 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.*

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10.8 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.

10.9 Letter Agreement, dated March 28, 2007, with Ares Corporate Opportunities Fund, 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 Form 8-K (File No. 001-32743), dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.

10.10 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.*

10.11 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.*

10.12 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.*

10.13 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.*

10.14 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.

10.15 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.

10.16 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.

10.17 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.

10.18 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.

10.19 Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.20 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.

10.21 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.

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10.22 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.

10.23 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.

10.24 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.

10.25 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.

10.26 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.

10.27 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.

10.28 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.*

10.29 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.*

10.30 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.*

10.31 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.

10.32 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.

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

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

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10.35 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.

10.36 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.

10.37 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.

10.38 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.

10.39 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.

10.40 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.

10.41 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.

10.42 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.*

10.43 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.*

10.44 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.*

10.45 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.*

10.46 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.

10.47 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.

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

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

101.INS XBRL Instance Document.

101.SCH XBRL Taxonomy Extension Schema Document.

101.CAL XBRL Taxonomy Calculation Linkbase Document.

101.DEF XBRL Taxonomy Definition Linkbase Document.

101.LAB XBRL Taxonomy Label Linkbase Document.

101.PRE XBRL Taxonomy Presentation Linkbase Document.

* These exhibits are management contracts.

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