Form 10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-Q 1 d326005d10q.htm FORM 10-Q Form 10-Q

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, 2012

¨	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 ¨

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 ¨

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

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

The number of shares of common stock, par value $0.001 per share, outstanding as of April 25, 2012 was 216,657,221.

EXCO RESOURCES, INC.

INDEX


PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	2
	Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011	2
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011	4
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011	5
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2012 and 2011	6
	Notes to Condensed Consolidated Financial Statements

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	45

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 5.	Other Information	46
Item 6.	Exhibits	47
	Signatures	48

PART I—FINANCIAL INFORMATION

Item 1.

Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31,			December 31,
(in thousands)	2012			2011
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	30,571		$	31,997
Restricted cash		164,042			155,925
Accounts receivable, net:
Oil and natural gas		49,133			88,518
Joint interest		130,183			170,918
Interest and other		28,392			28,488
Inventory		8,101			8,345
Derivative financial instruments		171,182			164,002
Other		21,246			29,815

Total current assets		602,850			678,008

Equity investments		295,064			302,833
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		623,268			667,342
Proved developed and undeveloped oil and natural gas properties		3,320,977			3,392,146
Accumulated depletion		(1,742,681	)		(1,657,165	)

Oil and natural gas properties, net		2,201,564			2,402,323

Gas gathering assets		136,740			136,203
Accumulated depreciation and amortization		(30,767	)		(29,104	)

Gas gathering assets, net		105,973			107,099

Office, field and other equipment, net		41,228			42,384
Deferred financing costs, net		28,101			29,622
Derivative financial instruments		10,073			11,034
Goodwill		218,256			218,256
Other assets		28			28

Total assets	$	3,503,137		$	3,791,587

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31,			December 31,
(in thousands, except per share and share data)	2012			2011
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	126,790		$	117,968
Revenues and royalties payable		117,657			148,926
Accrued interest payable		3,713			17,973
Current portion of asset retirement obligations		732			732
Income taxes payable		0			0
Derivative financial instruments		3,447			1,800

Total current liabilities		252,339			287,399

Long-term debt		1,918,106			1,887,828
Deferred income taxes		0			0
Derivative financial instruments		852			0
Asset retirement obligations and other long-term liabilities		59,006			58,028
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding		0			0
Common stock, $0.001 par value; 350,000,000 authorized shares; 217,197,701 shares issued and 216,658,480 shares outstanding at March 31, 2012; 217,245,504 shares issued and 216,706,283 shares outstanding at December 31, 2011		215			215
Additional paid-in capital		3,185,877			3,181,063
Accumulated deficit		(1,905,779	)		(1,615,467	)
Treasury stock, at cost; 539,221 shares at March 31, 2012 and December 31, 2011		(7,479	)		(7,479	)

Total shareholders’ equity		1,272,834			1,558,332

Total liabilities and shareholders’ equity	$	3,503,137		$	3,791,587

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended March 31,
(in thousands, except per share data)	2012			2011
Revenues:
Oil and natural gas	$	134,848		$	161,228
Costs and expenses:
Oil and natural gas operating costs		22,796			19,045
Production and ad valorem taxes		7,193			5,599
Gathering and transportation		26,423			17,286
Depreciation, depletion and amortization		89,582			67,930
Write-down of oil and natural gas properties		275,864			0
Accretion of discount on asset retirement obligations		947			857
General and administrative		21,505			23,423
Other operating items		1,625			2,457

Total costs and expenses		445,935			136,597

Operating income (loss)		(311,087	)		24,631
Other income (expense):
Interest expense		(16,764	)		(14,816	)
Gain on derivative financial instruments		53,865			3,421
Other income		243			160
Equity income (loss)		(7,906	)		8,545

Total other income (expense)		29,438			(2,690	)

Income (loss) before income taxes		(281,649	)		21,941
Income tax expense		0			0

Net income (loss)	$	(281,649	)	$	21,941

Earnings per common share:
Basic:
Net income (loss)	$	(1.32	)	$	0.10

Weighted average common shares outstanding		214,145			213,531

Diluted:
Net income (loss)	$	(1.32	)	$	0.10

Weighted average common and common equivalent shares outstanding		214,145			217,110

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three months ended March 31,
(in thousands)	2012			2011
Operating Activities:
Net income (loss)	$	(281,649	)	$	21,941
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		89,582			67,930
Share-based compensation expense		2,864			2,668
Accretion of discount on asset retirement obligations		947			857
Write-down of oil and natural gas properties		275,864			0
(Income) loss from equity investments		7,906			(8,545	)
Non-cash change in fair value of derivatives		(3,720	)		23,514
Deferred income taxes		0			0
Amortization of deferred financing costs; discount on the 2018 Notes and premium on the 2011 Notes		1,750			1,947
Effect of changes in:
Accounts receivable		78,796			(15,296	)
Other current assets		1,871			(2,813	)
Accounts payable and other current liabilities		(29,088	)		(13,130	)

Net cash provided by operating activities		145,123			79,073

Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(169,756	)		(199,610	)
Property acquisitions		(1,402	)		(506,833	)
Equity investments		(137	)		(162	)
Proceeds from disposition of property and equipment		981			259,103
Restricted cash		(8,117	)		11,125
Net changes in advances (to) from Appalachia JV		10,543			(5,063	)
Return of investment in equity investments		0			125,000
Deposit on acquisitions		0			464,151
Other		0			(1,250	)

Net cash provided by (used in) investing activities		(167,888	)		146,461

Financing Activities:
Borrowings under credit agreements		53,000			40,000
Repayments under credit agreements		(23,000	)		(300,000	)
Proceeds from issuance of common stock		2			7,312
Payment of common stock dividends		(8,663	)		(8,547	)

Net cash provided by (used in) financing activities		21,339			(261,235	)

Net decrease in cash		(1,426	)		(35,701	)
Cash at beginning of period		31,997			44,229

Cash at end of period	$	30,571		$	8,528


Supplemental Cash Flow Information:
Cash interest payments	$	34,883		$	32,809

Income tax payments	$	0		$	0

Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	1,931		$	1,380

Capitalized interest	$	6,302		$	7,740

Issuance of common stock for director services	$	17		$	15

See accompanying notes.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


												Additional		Retained			Total
	Common Stock					Treasury Stock						paid-in		earnings			shareholders’
(in thousands)	Shares			Amount		Shares			Amount			capital		(deficit)			equity
Balance at December 31, 2010		213,736		$	214		(539	)	$	(7,479	)	$	3,151,513	$	(1,603,696	)	$	1,540,552
Issuance of common stock		551			0								7,327					7,327
Share-based compensation													4,048					4,048
Common stock dividends															(8,547	)		(8,547	)
Net income															21,941			21,941

Balance at March 31, 2011		214,287		$	214		(539	)	$	(7,479	)	$	3,162,888	$	(1,590,302	)	$	1,565,321

Balance at December 31, 2011		217,245		$	215		(539	)	$	(7,479	)	$	3,181,063	$	(1,615,467	)	$	1,558,332
Issuance of common stock		2			0								19					19
Share-based compensation													4,795					4,795
Restricted stock cancellations		(49	)		0													0
Common stock dividends															(8,663	)		(8,663	)
Net loss															(281,649	)		(281,649	)

Balance at March 31, 2012		217,198		$	215		(539	)	$	(7,479	)	$	3,185,877	$	(1,905,779	)	$	1,272,834

See accompanying notes.

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, development and production of onshore U.S. oil and natural gas properties. Our principal operations are conducted in certain key U.S. oil and natural gas areas including East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia. Our midstream joint ventures are treated as a separate business segment.

Our strategy is to appraise, develop and exploit our Haynesville, Bossier and Marcellus shale resources, primarily through horizontal drilling, and to leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. We continue to develop vertical drilling opportunities in our Permian Basin area as this region has high oil reserves and natural gas with a high liquid content. Our shale resource plays and midstream operations are conducted through four joint ventures with affiliates of BG Group, plc, or BG Group. A brief description of each joint venture follows:

•

East Texas/North Louisiana JV

A joint venture with BG Group covering an undivided 50% interest in a substantial portion of our assets in the East Texas/North Louisiana area including the Haynesville/Bossier shale and conventional shallow producing assets, or the East Texas/North Louisiana JV. The East Texas/North Louisiana JV is governed by a joint development agreement with our subsidiary, EXCO Operating Company, LP, or EXCO Operating, serving as operator. We report the operating results and financial position of the East Texas/North Louisiana JV using proportional consolidation.

•

TGGT

A joint venture with BG Group in which we each own a 50% interest in TGGT Holdings, LLC, or TGGT, which holds most of our East Texas/North Louisiana midstream assets. We use the equity method to account for our 50% investment in TGGT.

•

Appalachia JV

A joint venture with BG Group covering our shallow producing assets and Marcellus shale acreage in the Appalachia region, or the Appalachia JV. EXCO and BG Group each own an undivided 50% interest in the JV and a 49.75% working interest in the joint venture properties. The remaining 0.5% working interest is owned by a jointly owned operating entity, or OPCO, that manages the Appalachia JV operations. Under the terms of the agreement, BG Group agreed to fund 75% of our share of deep drilling and completion costs within our joint venture area up to a total of $150.0 million, or the Appalachia Carry. As of March 31, 2012, the remaining balance of the Appalachia Carry was approximately $29.7 million. We use the equity method to account for our investment in OPCO and proportionally consolidate our 49.75% interest in the Appalachia area oil and natural gas exploration, development and production.

•

Appalachia Midstream JV

A joint venture with BG Group in which we each own a 50% interest in a midstream company, or the Appalachia Midstream JV, which will develop infrastructure and provide take-away capacity in the Marcellus shale. We use the equity method to account for our 50% investment in the Appalachia Midstream JV.

Our acquisition strategy for the past several years has been focused on the shale resources and consisted primarily of undeveloped acreage acquisitions. Our operations in the DeSoto Parish area of the Haynesville shale, or DeSoto Parish, are in the manufacturing phase and we have substantially completed our drilling activities to hold our acreage positions in Shelby, Nacogdoches and San Augustine Counties in East Texas, or the Shelby Area. Our Marcellus shale areas of interest have been identified and we have

begun a development program in Northeast Pennsylvania. While we expect to continue to evaluate acquisition opportunities in our Haynesville/Bossier and Marcellus shale areas, we have deployed our business development and technical staff to evaluate opportunities in new areas.

The accompanying Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011, 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, 2012 and 2011 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, or GAAP.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission, or the 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, 2012 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 our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 27, 2012.

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. Certain prior quarter amounts have been reclassified to conform to current quarter reporting.

2.	Significant accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, estimates of Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as significant accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 27, 2012.

3.	Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2012:


(in thousands)
Asset retirement obligations at January 1, 2012	$	58,088
Activity during the period:
Liabilities incurred during the period		264
Liabilities settled during the period		(165	)
Accretion of discount		947

Asset retirement obligations at March 31, 2012		59,134
Less current portion		732

Long-term portion	$	58,402

Our 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.

4.	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 intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds. 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 $623.3 million and $667.3 million as of March 31,

2012 and December 31, 2011, 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 and transfer unproved costs to proved properties as a result of extensions or discoveries from drilling operations or determination that no Proved Reserves are attributable to such costs. 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. No impairment of undeveloped properties occurred during the first quarter of 2012.

When we acquire significant amounts of undeveloped acreage, we capitalize interest on the acquisition costs in accordance with Financial Accounting Standards Board, or FASB, Accounting Standards Codification, or ASC, Subtopic 835-20 for Capitalization of Interest. We capitalize interest upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. 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.

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 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. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our exploration, exploitation and development activities.

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, or 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 is less than the full cost pool, we must record a ceiling test write-down of our oil and natural gas properties to the value of the full cost ceiling. 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 average prices 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.

The ceiling test is computed using the simple average spot price for the trailing twelve month period using the first day of each month. For the three months ended March 31, 2012, the trailing twelve month reference price was $98.15 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma and $3.73 per Mmbtu for natural gas at Henry Hub. Each of the reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results. For the three months ended March 31, 2012, we recognized a pre-tax ceiling test write-down of $275.9 million to our proved oil and natural gas properties. There was no ceiling test write-down for the three months ended March 31, 2011.

The ceiling test calculation is based upon 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 revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

5.	Earnings per share

We account for earnings per share in accordance with FASB ASC Subtopic 260-10 for Earnings Per Share, or ASC 260-10. ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per share for the three months ended March 31, 2012 and 2011 equals the net income divided by the weighted average common shares outstanding during the periods. Diluted earnings per common share for the three months ended March 31, 2012 and 2011 are computed in the same manner as basic earnings per share after assuming issuance of common stock for all potentially dilutive common stock equivalents, whether exercisable or not. We excluded 18,132,804 and 560,486 antidilutive common stock equivalents from the three months ended March 31, 2012 and 2011, respectively, computations of diluted earnings per share.

The following table presents the basic and diluted earnings per share computations:


	Three months ended March 31,
(in thousands, except per share amounts)	2012			2011
Basic income per common share:
Net income (loss)	$	(281,649	)	$	21,941

Shares:
Weighted average number of common shares outstanding		214,145			213,531

Basic income (loss) per common share:
Net income (loss) per common share	$	(1.32	)	$	0.10

Diluted income (loss) per common share:
Net income (loss)	$	(281,649	)	$	21,941

Shares:
Weighted average number of common shares outstanding		214,145			213,531
Dilutive effect of:
Stock options		0			3,579
Restricted shares		0			0

Weighted average number of common shares and common stock equivalent shares outstanding		214,145			217,110

Diluted income (loss) per common share:
Net income (loss) per common share	$	(1.32	)	$	0.10

6.	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 in connection with our 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 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.

We account for our derivative financial instruments in accordance with FASB ASC Topic 815, Derivatives and Hedging, or ASC 815, which requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. ASC 815 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 exist. 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 currently 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)	Balance Sheet location	March 31, 2012			December 31, 2011
Commodity contracts	Derivative financial instruments - Current assets	$	171,182		$	164,002
Commodity contracts	Derivative financial instruments - Long-term assets		10,073			11,034
Commodity contracts	Derivative financial instruments - Current liabilities		(3,447	)		(1,800	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(852	)		0

Net derivatives		$	176,956		$	173,236

The Effect of Derivative Financial Instruments


		Three months ended March 31,
(in thousands)	Statement of Operations location	2012		2011
Commodity contracts (1)	Gain on derivative financial instruments	$	53,865	$	3,421

(1)	Included in these amounts are net cash receipts of $50,145 and $26,935 for the three months ended March 31, 2012 and 2011, respectively.

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

are included in income with a corresponding increase or decrease in the Condensed Consolidated Balance Sheet fair value amounts. Unrealized fair value adjustments included in “Gain on derivative financial instruments,” which do not impact cash flows, were gains of $3.7 million and losses of $23.5 million for the three months ended March 31, 2012 and 2011, respectively.

We place our derivative financial instruments with the financial institutions that are lenders under our credit agreement that we believe have high quality credit ratings. To mitigate our risk of loss due to default, we have entered into master netting agreements with 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.

The following table presents the volume and fair value of our oil and natural gas derivative financial instruments as of March 31, 2012:


(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at March 31, 2012
Natural gas:
Swaps:
Remainder of 2012		60,500	$	5.27	$	167,304
2013		5,475		5.99		13,626

Total natural gas		65,975				180,930


Oil:
Swaps:
Remainder of 2012		413		98.05		(2,666	)
2013		365		99.96		(1,308	)

Total oil		778				(3,974	)

Total oil and natural gas derivatives					$	176,956

At December 31, 2011, we had outstanding derivative contracts to mitigate price volatility covering 85,995 Mmcf of natural gas and 275 Mbbls of oil. At March 31, 2012, the average forward NYMEX oil prices per Bbl for the remainder of 2012 and for 2013 were $104.54 and $103.59, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2012 and for 2013 were $2.50 and $3.47, respectively.

Our derivative financial instruments used to mitigate price volatility covered approximately 42.4% and 54.7% of production volumes for the three months ended March 31, 2012 and 2011, respectively.

7.	Fair value measurements

We value our derivatives according to FASB ASC Topic 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. This fair value 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.

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

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

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

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

Fair value of derivative financial instruments

The following table presents a summary of the estimated fair value of our derivative financial instruments as of March 31, 2012 and December 31, 2011. During the three months ended March 31, 2012, there were no changes in the fair value level classifications.


	March 31, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	176,956	$	—	$	176,956


	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	173,236	$	—	$	173,236

We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them gross 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. 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, or LIBOR, curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

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

Oil derivatives. Our oil derivatives are swap contracts for notional Bbls of oil at fixed NYMEX West Texas Intermediate (WTI) oil 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 WTI oil, and (iii) the applicable estimated credit-adjusted risk-free rate curve, as described above.

Natural gas derivatives. Our natural gas derivatives are swap contracts for notional Mmbtus of gas at posted price indexes, including NYMEX Henry Hub (HH) swap 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, and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

See further details on the fair value of our derivative financial instruments in “Note 6. Derivative financial instruments.”

Fair value of other financial instruments

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

The estimated fair value of our 7.5% senior unsecured notes due September 15, 2018, or the 2018 Notes, for the periods ended March 31, 2012 and December 31, 2011 are presented below. The estimated fair value of the 2018 Notes has been calculated based on market quotes.


	March 31, 2012
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	673,125	$	—	$	—	$	673,125


	December 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
2018 Notes	$	705,000	$	—	$	—	$	705,000

8.	Long-term debt

Our total debt is summarized as follows:


(in thousands)	March 31, 2012			December 31, 2011
EXCO Resources Credit Agreement	$	1,177,500		$	1,147,500
2018 Notes		750,000			750,000
Unamortized discount on 2018 Notes		(9,394	)		(9,672	)

Total debt	$	1,918,106		$	1,887,828

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

EXCO Resources Credit Agreement

As of March 31, 2012, the EXCO Resources Credit Agreement had a borrowing base of $1.6 billion, with $1.2 billion of outstanding indebtedness and $414.5 million of available borrowing capacity. On March 31, 2012, the one month LIBOR was 0.2%, which would result in an interest rate of approximately 2.2%. The borrowing base is redetermined semi-annually, with us and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. Please see “Note 14. Subsequent events” regarding the April 2012 redetermination of the borrowing base under the EXCO Resources Credit Agreement. Our next scheduled redetermination is in October 2012. The maturity date of the agreement is April 1, 2016.

The majority of our subsidiaries are guarantors under the EXCO Resources Credit Agreement. The EXCO Resources Credit Agreement permits investments, loans and advances to the unrestricted subsidiaries related to our joint ventures with certain limitations, and allows us to repurchase up to $200.0 million of our common stock, of which $7.5 million had been utilized as of March 31, 2012.

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 EXCO Resources Credit 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 EXCO Resources Credit Agreement) during the first two years of the forthcoming five-year period, 90% of the forecasted production for any month during the third year of the forthcoming five-year period and 85% of the forecasted production from total Proved Reserves during the fourth and fifth year 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 $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 borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes.

As of March 31, 2012, 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 ending on or after March 31, 2012.

While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under the EXCO Resources Credit Agreement is sufficient to conduct our operations into 2013, there are certain risks arising from further declines in natural gas prices that could impact our ability to meet debt covenants in future periods. In particular, our consolidated funded indebtedness to consolidated EBITDAX, as defined in the EXCO Resources Credit Agreement, is computed using the trailing twelve month EBITDAX. As a result, our ability to maintain compliance with this covenant may be negatively impacted when oil

and/or natural gas prices decline for an extended period of time. Our available borrowing base under the EXCO Resources Credit Agreement was reduced to $1.4 billion effective April 27, 2012. The possibility of further reductions to our borrowing base exists if natural gas prices remain at low levels.

In response to the declines in natural gas prices, we have reduced our drilling plans, which will likely reduce our production volumes late in 2012 and into 2013, and have taken measures to reduce operating and administrative expenses. In addition, the volumes of natural gas currently covered by derivative financial instruments declines significantly in 2013. We may enter into additional derivative financial instrument transactions as opportunities arise. The combination of a lower borrowing base, lower production volumes and reduced percentages of volumes covered by derivative financial instruments may result in our seeking alternative financing arrangements, further reducing costs or selling assets.

2018 Notes

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

As of March 31, 2012, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at March 31, 2012 was $9.4 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $673.1 million on March 31, 2012.

Interest accrues at 7.5% and is payable semi-annually in arrears on March 15 and September 15 of each year, beginning on March 15, 2011.

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 (over $50.0 million per annum) or redeem, repurchase or retire our capital stock or subordinated debt;

•

make certain investments;

•

create liens on our assets;

•

enter into sale/leaseback transactions;

•

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

•

engage in transactions with our affiliates;

•

transfer or issue shares of stock of subsidiaries;

•

transfer or sell assets; and

•

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

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

9.	Dividends

On March 1, 2012, our board of directors approved a cash dividend of $0.04 per share for the first quarter of 2012. The total cash dividend was $8.7 million, of which $8.6 million was paid on March 30, 2012 to holders of record on March 15, 2012 and $0.1 million was accrued to be paid to restricted shareholders when their shares vest. Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to limitations under the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the approval of our board of directors.

10.

Income taxes

Each quarter we evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws 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 ceiling test write-downs to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Also, we have tax net operating losses as a result of our drilling programs. For the three months ended March 31, 2012, we estimate that we generated $106.6 million of valuation allowance. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $482.1 million as of March 31, 2012. 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.

11.

Segment information

We follow FASB ASC Topic 280 for Segment Reporting, or ASC 280, when reporting operating segments. Pursuant to ASC 280, our reportable segments consist of exploration and production and midstream. The exploration and production segment is responsible for acquisition, development and production of oil and natural gas. The midstream segment, which consists of TGGT and Appalachia Midstream, is accounted for using the equity method and is responsible for purchasing, gathering, transporting and treating natural gas.

Prior to formation of TGGT in August 2009, our reportable segments consisted of exploration and production and wholly-owned midstream subsidiaries that were consolidated in our financial statements. We evaluated the performance of our operating segments based on segment profits, which include segment revenues, excluding the gain (loss) on derivative financial instruments, from external and internal customers and direct segment costs and expenses. Segment profit excludes items such as income taxes, interest income, interest expense, corporate expenses, depreciation and depletion and other items.

At the formation of TGGT on August 14, 2009, we determined that our midstream segment was no longer required due to the 50% reduction in the midstream segment’s profits and the application of equity method accounting. Due to the significant capital investments and growth within TGGT since its inception and the expected growth of Appalachia Midstream, as of December 31, 2011, we consider our midstream equity investments as a reportable segment. As a result of the designation of the midstream segment, we have restated the three months ended March 31, 2011 to reflect midstream as a segment. Our management evaluates TGGT’s and Appalachia Midstream’s performance on a standalone basis. The revenues and expenses used to compute the midstream’s segment profit represent TGGT’s and Appalachia Midstream’s results of operations without regard to our 50% ownership. Since we use the equity method of accounting for TGGT, we eliminate these revenues and expenses when reconciling to our consolidated results of operations and report our net share of midstream’s operations as equity income (loss). See “Note. 12—Equity investments” for additional details related to our equity investments, including our midstream segment.

Summarized financial information concerning our reportable segments is shown in the following table:


(in thousands)	Exploration and production			Midstream			Equity investee and intercompany eliminations			Consolidated total
For the three months ended March 31, 2012:
Third party revenues	$	134,848		$	62,924		$	(62,924	)	$	134,848
Intersegment revenues		0			0			0			0

Total revenues	$	134,848		$	62,924		$	(62,924	)	$	134,848

Segment profit	$	78,436		$	42,321		$	(42,321	)	$	78,436

Equity income (loss)	$	(408	)	$	(7,498	)	$	0		$	(7,906	)

For the three months ended March 31, 2011:
Third party revenues	$	161,228		$	54,182		$	(54,182	)	$	161,228
Intersegment revenues		0			0			0			0

Total revenues	$	161,228		$	54,182		$	(54,182	)	$	161,228

Segment profit	$	119,298		$	29,951		$	(29,951	)	$	119,298

Equity income (loss)	$	(47	)	$	8,592		$	0		$	8,545

As of March 31, 2012:
Capital expenditures	$	162,257		$	71,521		$	(71,521	)	$	162,257

Goodwill	$	218,256		$	0		$	0		$	218,256

Total assets	$	3,503,137		$	1,261,208		$	(1,261,208	)	$	3,503,137

As of December 31, 2011:
Capital expenditures	$	1,001,206		$	284,288		$	(284,288	)	$	1,001,206

Goodwill	$	218,256		$	0		$	0		$	218,256

Total assets	$	3,791,587		$	1,255,977		$	(1,255,977	)	$	3,791,587

The following table reconciles the segment profits reported above to income (loss) before income taxes:


	Three months ended March 31,
(in thousands)	2012			2011
Segment profits	$	78,436		$	119,298
Depreciation, depletion and amortization		(89,582	)		(67,930	)
Write-down of oil and natural gas properties		(275,864	)		0
Accretion of discount on asset retirement obligations		(947	)		(857	)
General and administrative		(21,505	)		(23,423	)
Other operating items		(1,625	)		(2,457	)
Interest expense		(16,764	)		(14,816	)
Gain on derivative financial instruments		53,865			3,421
Other income		243			160
Equity income (loss)		(7,906	)		8,545

Income (loss) before income taxes	$	(281,649	)	$	21,941

12.

Equity investments

We hold equity investments in four entities with BG Group, which are described below. We use the equity method of accounting for each investment.

•

We have a 50% ownership in TGGT, which holds interests in midstream assets in East Texas and North Louisiana. For the three months ended March 31, 2012, TGGT recorded an impairment of approximately $35.4 million of certain assets ($17.7 million net to us) associated with the installation of temporary treating facilities in response to

an incident at a TGGT amine treating facility in May 2011. After completion of an independent engineering study, the decision was made to activate the permanent facility affected by the incident since that facility had not sustained as much damage as was initially contemplated. The impairment primarily resulted from costs incurred related to temporary treating facilities that were not utilized or determined to have a shorter utilization period than originally anticipated. In addition, lower than expected throughput volumes at the facility as a result of reduced drilling contributed to the impairment.

•

We own a 50% interest in OPCO, which operates the Appalachia JV properties, subject to oversight from a management board having equal representation from EXCO and BG Group. During the first three months of 2012, EXCO and BG Group each contributed $0.1 million to OPCO, which is equal to OPCO’s 0.5% interest in any property acquisitions and the capital contributions for OPCO’s drilling and operating budget needs.

•

We own a 50% interest in the Appalachia Midstream JV, through which we and BG Group will pursue the construction and expansion of gathering systems for anticipated future production from the Marcellus shale.

•

We own a 50% interest in an entity that manages certain surface acreage.

The following tables present summarized consolidated financial information of our equity investments and a reconciliation of our investment to our proportionate 50% interest.


(in thousands)	March 31, 2012		December 31, 2011
Assets
Total current assets	$	186,127	$	227,911
Property and equipment, net		1,195,480		1,173,642
Other assets		5,438		6,570

Total assets	$	1,387,045	$	1,408,123

Liabilities and members’ equity
Total current liabilities	$	207,217	$	256,794
Total long term liabilities		507,645		462,669
Members’ equity:
Total members’ equity		672,183		688,660

Total liabilities and members’ equity	$	1,387,045	$	1,408,123


	Three months ended
(in thousands)	March 31, 2012			March 31, 2011
Revenues
Oil and natural gas	$	105		$	126
Midstream		62,924			54,182

Total revenues		63,029			54,308

Costs and expenses:
Oil and natural gas production		57			(7	)
Midstream operating		20,603			24,231
Asset impairment		35,343			0
General and administrative		7,408			5,080
Depreciation, depletion, and amortization		9,302			6,505
Other expenses		6,828			2,012

Total costs and expenses		79,541			37,821

Income (loss) before income taxes		(16,512	)		16,487
Income tax expense		238			335

Net income (loss)	$	(16,750	)	$	16,152

EXCO’s share of equity (loss) income before amortization	$	(8,375	)	$	8,076

Amortization of the difference in the historical basis of our contribution	$	469		$	469

EXCO’s share of equity (loss) income after amortization	$	(7,906	)	$	8,545

(in thousands)	March 31, 2012			December 31, 2011
Equity investments	$	295,064		$	302,833
Basis adjustment (1)		45,755			45,755
Cumulative amortization of basis adjustment (2)		(4,727	)		(4,258	)

EXCO’s 50% interest in equity investments	$	336,092		$	344,330

(1)

Our equity in TGGT and OPCO, at inception, exceeded the book value of our investments by an aggregate of $45.8 million, comprised of an aggregate $57.2 million difference in the historical basis of our contribution and the fair value of BG Group’s contribution, offset by $11.4 million of goodwill included in our investment in TGGT.

(2)	The aggregate $57.2 million basis difference is being amortized over the estimated life of the associated assets.

13.

Related party transactions

TGGT and OPCO

TGGT provides us with gathering, treating and well connect services in the ordinary course of business. In addition, TGGT also purchases natural gas from us in certain areas. OPCO serves as the operator of our wells in the Appalachia JV. There are service agreements between us and TGGT and OPCO whereby we provide administrative and technical services for which we are reimbursed. For the three months ended March 31, 2012 and 2011, these transactions included the following:


	Three months ended March 31,
	2012				2011
(in millions)	TGGT		OPCO		TGGT		OPCO
Amounts paid
Gathering, treating and well connect fees (1)	$	54.1			$	41.9
Advances to operator			$	4.9			$	20.4
Amounts received
Natural gas purchases	$	5.1			$	10.0
General and administrative services		6.0	$	12.7		3.4	$	11.8
Purchase of gathering and other assets		0				3.4
Other		0.7				0.1

Total	$	11.8	$	12.7	$	16.9	$	11.8

(1)	Represents the gross billings from TGGT.


	March 31, 2012				December 31, 2011
(in millions)	TGGT		OPCO		TGGT		OPCO
Amounts due to EXCO	$	3.7	$	7.9	$	8.2	$	8.2
Amounts due from EXCO (1)		20.1		3.8		39.4		0.0

(1)

Due to the relationship of OPCO being the operator of our wells, we advance funds on an as needed basis, which we include 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.

14.

Subsequent events

On April 27, 2012, we completed our semi-annual borrowing base redetermination with our banking group. The borrowing base was established at $1.4 billion, with an interest grid of LIBOR plus 175 bps to 275 bps (or ABR plus 75 bps to 175 bps). Our debt to EBITDA covenant was changed to 4.5 to 1.0 from 4.0 to 1.0, effective for the quarter ended March 31, 2012 and thereafter. The amendment also provides for asset sale procedures for sales of oil and natural gas properties or other material assets, including our interest in TGGT Holdings, LLC, whereby the proceeds from asset sales (over a minimum threshold) will be used to pay down the outstanding debt balance under the credit agreement and will also reduce the borrowing base. The borrowing base reduction will be equal to the borrowing base value assigned to the assets sold (if any) plus cash proceeds in excess of the borrowing base value aggregating up to $200 million.

In April 2012, we entered into commodity swap transactions for an additional 35,000 Mmbtu per day at an average price of $4.18 per Mmbtu for 2013, 2014 and 2015. The derivative contracts give the counterparty an option to cause EXCO to enter into derivative contracts at future dates. These options are exercisable monthly on the settlement date for each monthly contract. If the counterparty elects to exercise their option, the notional volume will increase by 35,000 Mmbtu per day at the average price of $4.18 per Mmbtu.

15.

Condensed consolidating financial statements

As of March 31, 2012, the majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes. All of our non-guarantor subsidiaries are 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, 2012:

•

Our equity method investment in OPCO represented $2.1 million of equity method investments and contributed $0.4 million of equity method losses; and

•

Our interests in jointly held entities with BG Group, with the exception of OPCO, represented $293.0 million of equity method investments, or 8.4% of our total assets and contributed $7.5 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, 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 are wholly-owned subsidiaries of Resources and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries.

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

•

Resources;

•

the Guarantor Subsidiaries on a combined basis;

•

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. The financial information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

March 31, 2012


(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	51,649		$	(21,078	)	$	0		$	0		$	30,571
Restricted cash		0			164,042			0			0			164,042
Other current assets		182,984			225,253			0			0			408,237

Total current assets		234,633			368,217			0			0			602,850

Equity investments		0			0			295,064			0			295,064
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		13,038			610,230			0			0			623,268
Proved developed and undeveloped oil and natural gas properties		478,001			2,842,976			0			0			3,320,977
Accumulated depletion		(318,373	)		(1,424,308	)		0			0			(1,742,681	)

Oil and natural gas properties, net		172,666			2,028,898			0			0			2,201,564

Gas gathering, office and field equipment, net		26,885			120,316			0			0			147,201
Investments in and advances to affiliates		534,146			0			0			(534,146	)		0
Deferred financing costs, net		28,101			0			0			0			28,101
Derivative financial instruments		5,690			4,383			0			0			10,073
Goodwill		38,100			180,156			0			0			218,256
Other assets		1			27			0			0			28

Total assets	$	1,040,222		$	2,701,997		$	295,064		$	(534,146	)	$	3,503,137


Liabilities and shareholders’ equity
Current liabilities	$	31,343		$	220,996		$	0		$	0		$	252,339
Long-term debt		1,918,106			0			0			0			1,918,106
Deferred income taxes		0			0			0			0			0
Other liabilities		8,729			51,129			0			0			59,858
Payable to parent		(2,190,790	)		2,196,946			(6,156	)		0			0
Total shareholders’ equity		1,272,834			232,926			301,220			(534,146	)		1,272,834

Total liabilities and shareholders’ equity	$	1,040,222		$	2,701,997		$	295,064		$	(534,146	)	$	3,503,137

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2011


(in thousands)	Resources			Guarantor subsidiaries			Non-guarantor subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	78,664		$	(46,667	)	$	0		$	0		$	31,997
Restricted cash		0			155,925			0			0			155,925
Other current assets		177,709			312,377			0			0			490,086

Total current assets		256,373			421,635			0			0			678,008

Equity investments		0			0			302,833			0			302,833
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		15,942			651,400			0			0			667,342
Proved developed and undeveloped oil and natural gas properties		464,898			2,927,248			0			0			3,392,146
Accumulated depletion		(327,218	)		(1,329,947	)		0			0			(1,657,165	)

Oil and natural gas properties, net		153,622			2,248,701			0			0			2,402,323

Gas gathering, office and field equipment, net		27,815			121,668			0			0			149,483
Investments in and advances to affiliates		869,387			0			0			(869,387	)		0
Deferred financing costs, net		29,622			0			0			0			29,622
Derivative financial instruments		5,998			5,036			0			0			11,034
Goodwill		38,100			180,156			0			0			218,256
Other assets		3			25			0			0			28

Total assets	$	1,380,920		$	2,977,221		$	302,833		$	(869,387	)	$	3,791,587


Liabilities and shareholders’ equity
Current liabilities	$	39,395		$	248,004		$	0		$	0		$	287,399
Long-term debt		1,887,828			0			0			0			1,887,828
Deferred income taxes		0			0			0			0			0
Other liabilities		7,740			50,288			0			0			58,028
Payable to parent		(2,112,375	)		2,118,531			(6,156	)		0			0
Total shareholders’ equity		1,558,332			560,398			308,989			(869,387	)		1,558,332

Total liabilities and shareholders’ equity	$	1,380,920		$	2,977,221		$	302,833		$	(869,387	)	$	3,791,587

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2012


(in thousands)	Resources			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	23,273		$	111,575		$	0		$	0	$	134,848

Costs and expenses:
Oil and natural gas production		5,125			24,864			0			0		29,989
Gathering and transportation		0			26,423			0			0		26,423
Depreciation, depletion and amortization		(6,892	)		96,474			0			0		89,582
Write-down of oil and natural gas properties		0			275,864			0			0		275,864
Accretion of discount on asset retirement obligations		126			821			0			0		947
General and administrative		3,775			17,730			0			0		21,505
Other operating items		42			1,583			0			0		1,625

Total costs and expenses		2,176			443,759			0			0		445,935

Operating income (loss)		21,097			(332,184	)		0			0		(311,087	)
Other income (expense):
Interest expense		(16,764	)		0			0			0		(16,764	)
Gain on derivative financial instruments		49,223			4,642			0			0		53,865
Other income (expense)		36			207			0			0		243
Equity method income		0			0			(7,906	)		0		(7,906	)
Equity in earnings of subsidiaries		(335,241	)		0			0			335,241		0

Total other income (expense)		(302,746	)		4,849			(7,906	)		335,241		29,438

Income (loss) before income taxes		(281,649	)		(327,335	)		(7,906	)		335,241		(281,649	)
Income tax expense		0			0			0			0		0

Net income (loss)	$	(281,649	)	$	(327,335	)	$	(7,906	)	$	335,241	$	(281,649	)

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2011


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	23,386		$	137,842		$	0		$	0		$	161,228

Costs and expenses:
Oil and natural gas production		4,287			20,357			0			0			24,644
Gathering and transportation		0			17,286			0			0			17,286
Depreciation, depletion and amortization		6,566			60,993			371			0			67,930
Accretion of discount on asset retirement obligations		101			756			0			0			857
General and administrative		4,716			18,707			0			0			23,423
Other operating items		2,616			553			(712	)		0			2,457

Total costs and expenses		18,286			118,652			(341	)		0			136,597

Operating income		5,100			19,190			341			0			24,631
Other income (expense):
Interest expense		(13,564	)		(1,252	)		0			0			(14,816	)
Gain (loss) on derivative financial instruments		3,601			(180	)		0			0			3,421
Other income		84			76			0			0			160
Equity method income		0			0			8,545			0			8,545
Equity in earnings of subsidiaries		26,720			0			0			(26,720	)		0

Total other income (expense)		16,841			(1,356	)		8,545			(26,720	)		(2,690	)

Net income (loss)	$	21,941		$	17,834		$	8,886		$	(26,720	)	$	21,941

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2012


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	40,676		$	104,447		$	0	$	0	$	145,123

Investing Activities:
Property acquisitions and additions to oil and natural gas properties, gathering systems and equipment		(10,120	)		(161,038	)		0		0		(171,158	)
Equity investments		0			(137	)		0		0		(137	)
Proceeds from disposition of property and equipment		0			981			0		0		981
Restricted cash		0			(8,117	)		0		0		(8,117	)
Net changes in advances (to) from Appalachia JV		0			10,543			0		0		10,543
Advances/investments with affiliates		(78,910	)		78,910			0		0		0

Net cash used in investing activities		(89,030	)		(78,858	)		0		0		(167,888	)

Financing Activities:
Borrowings under credit agreements		53,000			0			0		0		53,000
Repayments under credit agreements		(23,000	)		0			0		0		(23,000	)
Proceeds from issuance of common stock		2			0			0		0		2
Payment of common stock dividends		(8,663	)		0			0		0		(8,663	)

Net cash provided by financing activities		21,339			0			0		0		21,339

Net increase (decrease) in cash		(27,015	)		25,589			0		0		(1,426	)
Cash at the beginning of the period		78,664			(46,667	)		0		0		31,997

Cash at end of period	$	51,649		$	(21,078	)	$	0	$	0	$	30,571

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2011


(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	18,448		$	59,468		$	1,157		$	0	$	79,073

Investing Activities:
Property acquisitions and additions to oil and natural gas properties, gathering systems and equipment		(17,463	)		(685,916	)		(3,064	)		0		(706,443	)
Restricted cash		0			11,125			0			0		11,125
Deposit on pending acquisitions		0			464,151			0			0		464,151
Equity investments		0			(162	)		0			0		(162	)
Return of investment in equity investments		0			125,000			0			0		125,000
Proceeds from disposition of property and equipment		39			259,064			0			0		259,103
Net changes in advances (to) from Appalachia JV		0			(5,063	)		0			0		(5,063	)
Other		0			(1,250	)		0			0		(1,250	)
Advances/investments with affiliates		233,700			(235,607	)		1,907			0		0

Net cash provided by (used in) investing activities		216,276			(68,658	)		(1,157	)		0		146,461

Financing Activities:
Borrowings under credit agreement		40,000			0			0			0		40,000
Repayments under credit agreement		(300,000	)		0			0			0		(300,000	)
Proceeds from issuance of common stock		7,312			0			0			0		7,312
Payment of common stock dividends		(8,547	)		0			0			0		(8,547	)

Net cash used in financing activities		(261,235	)		0			0			0		(261,235	)

Net decrease in cash		(26,511	)		(9,190	)		0			0		(35,701	)
Cash at the beginning of the period		76,763			(32,534	)		0			0		44,229

Cash at end of period	$	50,252		$	(41,724	)	$	0		$	0	$	8,528

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context requires otherwise, references 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 derivative financial instrument activities; 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,” “budget” and other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. 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 prices of oil and natural gas;

•

imports or exports of oil and natural gas, including liquefied natural gas;

•

future capital requirements and availability of financing;

•

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

•

estimates of reserves and economic assumptions;

•

geological concentration of our reserves;

•

risks associated with drilling and operating wells;

•

exploratory risks, including our Marcellus shale play in Appalachia and the Haynesville and Bossier shale plays in East Texas/North Louisiana;

•

risks associated with the operation of natural gas pipelines, gathering systems and treating facilities;

•

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;

•

marketing of oil and natural gas;

•

developments 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;

•

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

•

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. You are cautioned to not place undue reliance on a forward-looking statement. 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, 2011, filed with the Securities and Exchange Commission, or SEC, on February 27, 2012.

Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas and the availability of capital from the EXCO Resources Credit Agreement. 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. During the first quarter of 2012, natural gas prices for near-term months and futures markets experienced declines which may impact our liquidity, results of operations and development plans.

Overview and history

We are an independent oil and natural gas company engaged in the exploration, exploitation, 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 East Texas, North Louisiana, Appalachia and the Permian Basin in West Texas. In addition to our oil and natural gas producing operations, we own 50% interests in two midstream joint ventures located in East Texas/North Louisiana and Appalachia.

Our strategy is to appraise, develop and exploit our Haynesville, Bossier and Marcellus shale resources, primarily through horizontal drilling, and leverage our complementary midstream gathering facilities to promptly transport our production to multiple market outlets. We continue to develop vertical drilling opportunities in our Permian Basin area as this region has high oil reserves and natural gas with a high liquid content. Our shale resource plays and midstream operations are conducted through four joint ventures with affiliates of BG Group, plc, or BG Group. A brief description of each joint venture follows.

•

East Texas/North Louisiana JV

•

TGGT

•

Appalachia JV

•

Appalachia Midstream JV

Our plans for 2012 emphasize cost containment of operating and administrative expenses and reduction of drilling costs in response to a low natural gas price environment. In February 2012, we reduced our capital expenditure budget by 33.8% and we continue to evaluate the feasibility of drilling projects. We have reduced our operated drilling rigs in the Haynesville/Bossier shale from 22 during the fourth quarter of 2011 to nine as of March 31, 2012. In the Marcellus shale, we expect to operate three drilling rigs in 2012 compared to an original drilling program of five rigs. Our forecasted capital expenditures for 2012 total $470.0 million, of which $383.0 million is allocated to our East Texas/North Louisiana and Appalachia regions. In East Texas and North Louisiana, our capital expenditures for the East Texas/North Louisiana JV are expected to total $286.0 million in 2012. During the first three months of 2012, we spent $122.2 million in East Texas/North Louisiana, $119.7 million of which was in the area of mutual interest with BG Group, or the East Texas/North Louisiana AMI. In Appalachia, our share of planned capital expenditures for the Appalachia JV in 2012 are expected to total $91.0 million, which excludes $54.6 million of the Appalachia Carry. During the first three months of 2012, we spent $17.7 million in Appalachia, which reflects the impact of the Appalachia Carry. As of March 31, 2012, the remaining balance of the Appalachia Carry was approximately $29.7 million.

For 2012, TGGT’s capital expenditure budget totaling approximately $120.0 to $130.0 million, of which approximately $100.0 million is expected to be spent in the first half of 2012, will focus primarily on completing treating facilities in DeSoto Parish and the Shelby Area and completing pipeline infrastructure, particularly in the Shelby Area. The management of TGGT continues to evaluate several expansion projects, which will be primarily driven by natural gas prices and third party producer opportunities and believes cash flows from operations and borrowing capacity under its credit agreement will be sufficient to fund its 2012 capital expenditure programs.

We do not expect to make significant capital contributions in 2012 to our Appalachia Midstream JV as the majority of our Northeastern Pennsylvania development drilling accesses an existing third party gathering system.

Like all oil and natural gas production companies, we face the challenge of natural production declines. Oil and natural gas production from a given well naturally decreases over time. We attempt to offset the impact of this natural decline by drilling to identify and develop additional reserves and adding additional reserves through acquisitions.

Critical accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are 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 our Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 27, 2012.

Our results of operations

A summary of key financial data for the three months ended March 31, 2012 and 2011 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)	2012			2011			2012-2011
Production:
Oil (Mbbls)		192			193			(1	)
Natural gas (Mmcf)		47,381			35,525			11,856
Total production (Mmcfe) (1)		48,533			36,683			11,850
Average daily production (Mmcfe)		533			408			125
Oil and natural gas revenues before derivative financial instrument activities:
Oil	$	18,650		$	17,372		$	1,278
Natural gas		116,198			143,856			(27,658	)

Total oil and natural gas	$	134,848		$	161,228		$	(26,380	)

Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	50,145		$	26,935		$	23,210
Non-cash change in fair value of derivative financial instruments		3,720			(23,514	)		27,234

Total derivative financial instrument activities	$	53,865		$	3,421		$	50,444

Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	97.14		$	90.01		$	7.13
Natural gas (per Mcf)		2.45			4.05			(1.60	)
Natural gas equivalent (per Mcfe)		2.78			4.40			(1.62	)
Costs and expenses:
Oil and natural gas operating costs (2)	$	22,796		$	19,045		$	3,751
Production and ad valorem taxes		7,193			5,599			1,594
Gathering and transportation		26,423			17,286			9,137
Depletion		85,516			63,320			22,196
Depreciation and amortization		4,066			4,610			(544	)
General and administrative (3)		21,505			23,423			(1,918	)
Interest expense		16,764			14,816			1,948
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.47		$	0.52		$	(0.05	)
Production and ad valorem taxes		0.15			0.15			—
Gathering and transportation		0.54			0.47			0.07
Depletion		1.76			1.73			0.03
Depreciation and amortization		0.08			0.13			(0.05	)
General and administrative		0.44			0.64			(0.20	)
Net income (loss)	$	(281,649	)	$	21,941		$	(303,590	)

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

(2)	Share-based compensation included in oil and natural gas operating costs is $0.1 million for the three months ended March 31, 2011. There was no share-based compensation in oil and natural gas operating costs for the three months ended March 31, 2012.

(3)	Share-based compensation included in general and administrative expenses is $2.9 million and $2.6 million for the three months ended March 31, 2012 and 2011, respectively.

Following is a discussion of our financial condition and results of operations for the three months ended March 31, 2012 and 2011. The comparability of our results of operations from period to period is impacted by:

•

acquisitions in the Marcellus and Haynesville shale during 2011;

•

costs associated with a former acquisition proposal and other non-recurring costs;

•

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

•

mark-to-market accounting used for our derivative financial instruments gains or losses;

•

changes in Proved Reserves and production volumes and their impact on depletion;

•

the equity method of accounting for our investments, including certain asset impairments in TGGT;

•

the impact of our natural gas production volumes from our horizontal drilling activities in the Haynesville/Bossier and Marcellus shales;

•

ceiling test write-down in 2012; and

•

changes in the amount of our long-term debt.

General

The availability of a ready market for oil and natural gas and the prices of oil and natural gas 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, particularly the ongoing worldwide economic recession which continues to affect oil and natural gas prices and demand;

•

the current domestic oversupply of natural gas;

•

the ability to export domestic oil and natural gas;

•

the level of domestic and international industrial demand for manufacturing operations;

•

the available capacity at natural gas storage facilities;

•

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.

Marketing arrangements

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

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

We may be unable to market all of the oil and natural gas we produce. If our oil and natural gas can be marketed, we may be unable to negotiate favorable price and contractual terms. Changes in oil or natural gas prices may significantly affect our revenues, cash flows, the value of our oil and natural gas properties and the estimates of recoverable oil and natural gas reserves. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. In this situation, companies purchasing oil or natural gas in these areas reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our newly discovered oil or natural gas reserves, we may shut in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated. Economic conditions, particularly low natural gas prices, may negatively impact the liquidity and creditworthiness of our purchasers and may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.

Summary

For the three months ended March 31, 2012, we reported a net loss of $281.6 million compared to net income of $21.9 million for the three months ended March 31, 2011.

The decrease in net income for the three months ended March 31, 2012 from the same period in 2011 is primarily the result of a $275.9 million non-cash ceiling test write-down due to the significant declines in natural gas prices. We increased production to 48.5 Bcfe for the three months ended March 31, 2012 from 36.7 Bcfe for the three months ended March 31, 2011. However, a decline in average prices to $2.78 per Mcfe for the three months ended March 31, 2012 from $4.40 per Mcfe for the three months ended March 31, 2011 more than offset the production increase.

To mitigate fluctuations in oil and natural gas prices, we have entered into oil and natural gas swaps. We do not designate our derivative financial instruments as hedges. As a result, we mark non-cash changes in the fair value of unsettled derivative financial instruments to market at the end of each reporting period. The impacts of realized and unrealized gains of derivative financial instruments resulted in net gains of $53.9 million and $3.4 million for the three months ended March 31, 2012 and 2011, respectively.

Oil and natural gas production, revenues, and prices

The following table presents our production, revenue and average sales prices by major producing areas for the three months ended March 31, 2012 and 2011:


	Three months ended March 31,
	2012						2011						Quarter to quarter change
(dollars in thousands, except per unit rate)	Revenue		Production (Mmcfe)		$/Mcfe		Revenue		Production (Mmcfe)		$/Mcfe		Revenue			Production (Mmcfe)			$/Mcfe
Producing region:
East Texas/North Louisiana	$	101,077		42,943	$	2.35	$	125,206		31,945	$	3.92	$	(24,129	)		10,998		$	(1.57	)
Appalachia		10,498		3,645		2.88		12,637		2,780		4.55		(2,139	)		865			(1.67	)
Permian and other		23,273		1,945		11.97		23,385		1,958		11.94		(112	)		(13	)		0.03

Total	$	134,848		48,533		2.78	$	161,228		36,683		4.40	$	(26,380	)		11,850			(1.62	)

Production in our East Texas/North Louisiana region for the three months ended March 31, 2012 increased by 11.0 Bcfe from the same period in the prior year. This increase is the result of the continual development of our Haynesville shale during 2011 and into 2012. The increase in Haynesville production was partially offset by production declines of 0.7 Bcfe in our Vernon Field and 0.4 Bcfe from other shallow conventional wells in the region. The declines in the Vernon Field and other shallow conventional wells are the result of normal production declines together with the continued suspension of our vertical drilling operations. The increases in Appalachia are a result of our drilling in the Marcellus shale.

For the three months ended March 31, 2012, oil and natural gas revenues were $134.8 million, a 16.4% decrease from the oil and natural gas revenues of $161.2 million for the three months ended March 31, 2011. The decrease in revenues is primarily a result of a decline in natural gas prices, offset by increases in production and oil prices. Our average sales price of oil per Bbl, excluding the

impact of derivative financial instruments, increased 7.9% to $97.14 per Bbl for the three months ended March 31, 2012 from $90.01 per Bbl for the three months ended March 31, 2011. Our average natural gas sales price, excluding the impact of derivative financial instruments, was $2.45 per Mcf for the three months ended March 31, 2012 compared with $4.05 per Mcf for the three months ended March 31, 2011, a decrease of 39.5%.

The price we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, estimates of oil and natural gas in storage, weather and other seasonal conditions, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Weakness in natural gas prices persists. Changes in oil and natural gas prices have a significant impact on our oil and natural gas revenues, cash flows, quantities of estimated Proved Reserves and related liquidity. Assuming we maintain our three months ended March 31, 2012 average production levels for the remainder of the year, a change in the average sales price of $0.10 per Mcf of natural gas sold would result in an increase or decrease in revenues and cash flows of approximately $14.2 million and a change in the average sales price of $1.00 per Bbl of oil sold would result in an increase or decrease in revenues and cash flow of approximately $0.6 million, without considering the effects of derivative financial instruments.

In addition, our production volumes are impacted by shut-in volumes of natural gas due to operational requirements associated with fracture stimulation and other operations on near by horizontal wells, seasonal supply and demand conditions from end users and general maintenance and repairs to our wells. While these shut-in volumes are typically for short periods of time, they may have impacts to our revenues, cash flows and results of operations. We currently expect that approximately 7% to 8% of our Haynesville/Bossier shale production will be shut-in. At the end of the quarter ended March 31, 2012, TGGT completed construction of, and began operations at, a temporary treating facility and shut-in volumes have since decreased from levels experienced in the last half of 2011.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three months ended March 31, 2012 were $22.8 million compared with $19.0 million for the three months ended March 31, 2011. The increases are mainly due to 2012 workover activity in our Haynesville shale properties, costs associated with the producing properties acquired during the first quarter of 2011 in the Appalachia region and increased operating costs associated with additional wells in 2011 and 2012. To further analyze the variances in costs, management reviews the costs on a per Mcfe basis, as we believe this measure excludes the impact of any acquisitions or divestitures and actual operating expense trends due to fluctuating production volume.

As shown in the table below, on a per Mcfe basis, oil and natural gas operating expenses for the three months ended March 31, 2012 decreased $0.05 per Mcfe, a reduction of 9.6% from the same period in 2011. The net decrease in oil and natural gas operating expenses per Mcfe is primarily due to our Haynesville shale wells in East Texas/North Louisiana, which have continued to develop cost efficiencies as we have increased production. Our conventional Vernon Field and Cotton Valley properties have experienced offsetting increases in operating expenses on a per Mcfe basis due to increased workover activity and decreases in production resulting from suspension of drilling activities. The per Mcfe operating expense decreases in East Texas/North Louisiana were partially offset by increases in the Appalachia and Permian regions. Increases in Appalachia are primarily a result of higher operating costs associated with water disposal from horizontal Marcellus wells located in remote regions. The Permian region operating expenses per Mcfe increased due to higher costs associated with liquids production.


	Three months ended March 31,
	2012						2011						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	$	11,301	$	3,810	$	15,111	$	11,002	$	2,516	$	13,518	$	299	$	1,294	$	1,593
Appalachia		4,410		—		4,410		2,916		—		2,916		1,494		—		1,494
Permian and other		3,155		120		3,275		2,528		83		2,611		627		37		664

Total	$	18,866	$	3,930	$	22,796	$	16,446	$	2,599	$	19,045	$	2,420	$	1,331	$	3,751


	Three months ended March 31,
	2012						2011						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	$	0.26	$	0.09	$	0.35	$	0.34	$	0.08	$	0.42	$	(0.08	)	$	0.01	$	(0.07	)
Appalachia		1.21		—		1.21		1.05		—		1.05		0.16			—		0.16
Permian and other		1.62		0.06		1.68		1.29		0.04		1.33		0.33			0.02		0.35
Total	$	0.39	$	0.08	$	0.47	$	0.45	$	0.07	$	0.52	$	(0.06	)	$	0.01	$	(0.05	)

Midstream operations

We own a 50% equity interest in TGGT and the Appalachia Midstream JV. Our midstream operations earn fees from the gathering, treating and compression of natural gas. Additional operating margins are derived from purchases and resale of natural gas from third parties. Our midstream joint ventures do not own any natural gas processing facilities. We use the equity method of accounting for both of our midstream joint ventures.

TGGT holds our East Texas/North Louisiana midstream assets. TGGT’s primary customers are EXCO and BG Group. TGGT also owns and operates TGG Pipeline, Ltd., or TGG, and Talco Midstream Assets, Ltd., or Talco. The assets of TGG include treating facilities and gathering pipelines that connect to downstream pipelines. Talco’s assets primarily consist of gathering pipelines that provide well hookups and lateral connections.

TGG operates amine, glycol, and H₂S treating facilities, which treat natural gas to meet pipeline specifications for downstream transportation. TGG’s system, which has access to 14 interstate and intrastate pipeline markets, has approximately 127 miles of pipeline comprised of 12, 16, and 20-inch diameter pipe in the East Texas area and 27 miles of pipeline comprised of 36-inch diameter pipe in the North Louisiana area. The Shelby Area’s system has approximately 90 miles of operational pipeline comprised of 4-inch to 36-inch diameter pipe servicing Haynesville/Bossier producers as of March 31, 2012. In our Shelby area, a 20 mile pipeline project and a treating facility, which will provide treating capacity of approximately 250 Mmcf per day, are expected to become operational early in the second quarter of 2012. Once the Shelby pipeline and the treating facility are operational, it will conclude TGGT’s major infrastructure development in the Shelby area for 2012.

As of March 31, 2012, the Talco gathering system in East Texas consists of approximately 580 miles of 4-inch to 12-inch diameter pipe that provides gathering services to a significant number of producers, and Talco in North Louisiana consisted of approximately 280 miles of 2-inch to 16-inch pipe servicing Cotton Valley and Haynesville/Bossier producers.

In the second quarter 2011 an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana resulting in an immediate shut-down of the facility. TGGT installed temporary treating units at the damaged facility and began treating volumes late in the first quarter of 2012.

For the three months ended March 31, 2012, TGGT recorded an impairment of approximately $35.4 million related to certain assets ($17.7 million net to us) associated with the installation of temporary treating facilities in response to an incident at a TGGT amine treating facility in May 2011. After completion of an independent engineering study, the decision was made to activate the permanent facility affected by the incident since that facility had not sustained as much damage as was initially contemplated. The impairment primarily resulted from costs incurred related to temporary treating facilities that were not utilized or determined to have a shorter utilization period than originally anticipated. In addition, lower than expected throughput volumes at the facility as a result of reduced drilling contributed to the impairment.

The Appalachia Midstream JV continues to install and operate gathering systems and compression facilities to support our development drilling program in the Appalachia JV.

Gathering and transportation

We report gathering and transportation costs in accordance with FASB Section 605-45-05, Subtopic 605-45, Revenue Recognition. We generally sell oil and natural gas under two types of agreements which are common in our industry. Both types of agreements include a transportation charge. One is a netback arrangement, under which we sell oil or natural gas at the wellhead and collect a price, net of the transportation incurred by the purchaser. In this case, we record sales at the price received from the purchaser, net of the transportation costs. Under the other arrangement, we sell oil or natural gas at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In this case, we record the transportation cost as gathering and transportation expense. Due to these two distinct selling arrangements, our computed realized prices, before the impact of derivative financial instruments, contain revenues which are reported under two separate bases. Gathering and transportation expenses totaled $26.4 million for three months ended March 31, 2012, compared to $17.3 million for the three months ended March 31, 2011. The overall increase in gathering and transportation expenses is a result of increased production in Haynesville. We expect our gathering and transportation costs on a per Mcfe basis to increase in 2012 as a result of reduced drilling, which will increase unused firm transportation costs.

We have entered into firm transportation agreements with pipeline companies to facilitate sales as we expand our Haynesville volumes and report these firm transportation costs as a component of gathering and transportation expenses. As of March 31, 2012, our firm transportation agreements covered an average of 826 Mmcf per day with average annual minimum gathering and transportation expenses of approximately $93.3 million through 2021.

Production and ad valorem taxes

For the three months ended March 31, 2012, production and ad valorem taxes increased by $1.6 million, or 28.5%, over the same period in 2011. On a percentage basis, before the impact of derivative financial instruments, production and ad valorem taxes were 5.3% of gross oil and natural gas revenues for the three months ended March 31, 2012 compared with 3.5% during same period in the prior year.

In our East Texas/North Louisiana area, we are presently receiving severance tax holidays on certain Haynesville shale wells which reduce the effective rate of these taxes. While the state of Louisiana has a history of adjusting its severance tax rate each July, they have maintained a rate of $0.164 per Mcf since July 1, 2010.

In February 2012, the Commonwealth of Pennsylvania enacted Act 13, a comprehensive reform to Pennsylvania’s Oil and Gas Act, which requires an impact fee to be paid on all unconventional wells spud. The fee will range from $190,000 to $355,000 per well, based on a price tier calculation to be paid annually up to 15 years. The fee is payable for all wells spud in a single year by April 1 of the following year. The Act also requires this fee to be assessed on all unconventional wells spud prior to December 31, 2011. This initial fee of $2.0 million, which is payable September 1, 2012, was recorded in “Other operating items” on our Condensed Consolidated Statement of Operations for the three months ended March 31, 2012. The on-going fee, which will be recorded in “Production and ad valorem taxes”, is computed using the prior year’s trailing 12 month NYMEX natural gas price based on a tiered pricing system and will be paid annually for 15 years. For the three months ended March 31, 2012, we recorded $0.5 million for our estimated 2012 impact fees.

Production taxes are set by state and local governments and vary as to the tax rate and the value to which that rate is applied. Ad valorem tax rates also vary widely. In Louisiana, where a substantial percentage of our production is derived, severance taxes are levied on a per Mcf basis. Therefore, the resulting dollar value of production is not sensitive to changes in prices for natural gas, except for holiday exemptions, if any. In our other operating areas, particularly Texas, production taxes are based on a fixed percentage of gross value of products sold. While severance tax holidays are available in Texas, as our production increases, our realized severance and ad valorem tax rates may become more sensitive to prices.

Overall, our production and ad valorem tax rates per Mcfe were $0.15 per Mcfe for the three months ended March 31, 2012 and 2011. The following table presents our severance and ad valorem taxes on a per Mcfe basis and percentage of revenue basis for our significant producing regions.


	Three months ended March 31,
	2012											2011
(dollars in thousands, except per unit rate)	Revenue		Production (Mmcfe)		Production and ad valorem taxes		Taxes % of revenue			Taxes $/Mcfe		Revenue		Production (Mmcfe)		Production and ad valorem taxes		Taxes % of revenue			Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	101,077		42,943	$	4,469		4.4	%	$	0.10	$	125,206		31,945	$	3,634		2.9	%	$	0.11
Appalachia		10,498		3,645		874		8.3	%		0.24		12,637		2,780		289		2.3	%		0.10
Permian and other		23,273		1,945		1,850		7.9	%		0.95		23,385		1,958		1,676		7.2	%		0.86

Total	$	134,848		48,533	$	7,193		5.3	%		0.15	$	161,228		36,683	$	5,599		3.5	%		0.15

Depletion, depreciation and amortization

Our depletion expense for the three months ended March 31, 2012 increased by $22.2 million from the same period in 2011. The increase is primarily the result of higher production volumes and capital expenditures associated with development drilling during 2011 and 2012. On a per Mcfe basis, our depletion rate for the three months ended March 31, 2012 was $1.76 compared with $1.73 for the comparable prior year period. For the remainder of 2012, we expect our per Mcfe depletion rate will be lowered by additional ceiling test write-downs. We expect the Appalachia Carry to be utilized during the fourth quarter of 2012, which will increase the per Mcfe rate late in 2012.

Our depreciation and amortization costs for the three months ended March 31, 2012 decreased by $0.5 million, or 11.8% from the same period in 2011.

Accretion of discount on asset retirement obligations for the three months ended March 31, 2012 increased by $0.1 million, or 10.5% from the same period in 2011. The increase is a result of the 2011 acquisitions along with increased drilling programs in both the Haynesville shale and Marcellus shale.

Write-down of oil and natural gas properties

For the three months ended March 31, 2012, we recognized a pre-tax ceiling test write-down of $275.9 million due primarily to low natural gas prices. There were no ceiling test write-downs during the first quarter of 2011.

The ceiling test computation is based on the arithmetic average of reference prices on the first day of the month for the preceding 12 months at each balance sheet date. Natural gas prices on April 1, 2012 were lower than April 1, 2011, which would continue to lower the trailing 12 month average in 2012. As a result, we expect to incur additional ceiling test write-downs in 2012 if prices do not increase.

General and administrative

The following table presents our general and administrative expenses for the three months ended March 31, 2012:


	Three months ended March 31,						Quarter to
(in thousands, except per unit rate)	2012			2011			quarter change
General and administrative costs:
Gross general and administrative expense	$	41,412		$	40,586		$	826
Technical services and service agreement charges		(7,049	)		(6,153	)		(896	)
Operator overhead reimbursements		(5,240	)		(4,318	)		(922	)
Capitalized salaries and share-based compensation		(7,618	)		(6,692	)		(926	)

General and administrative expense	$	21,505		$	23,423		$	(1,918	)

General and administrative expense per Mcfe	$	0.44		$	0.64		$	(0.20	)

Our general and administrative costs for the three months ended March 31, 2012 were $21.5 million, or $0.44 per Mcfe, compared to $23.4 million, or $0.64 per Mcfe, for the same period in 2011.

Significant components of the net decrease for the three months ended March 31, 2012 compared to the respective 2011 period was a result of:

•

increased service agreement recoveries from BG Group as a result of an increased drilling program;

•

increased overhead recoveries of $0.9 million arising from additional wells drilled in 2011;

•

increased share based compensation of $0.3 million and capitalized salaries of $0.6 million;

•

a $1.0 million reduction of expected cash bonus payments in 2012; and

•

decreased office rental and miscellaneous expenses of $0.7 million.

The above decreases were partially offset by increased personnel costs of $2.4 million, mostly attributable to an employee retention plan implemented during the third quarter of 2011 and increased legal expenses of $0.9 million.

Operating items

Our other operating expenses for the three months ended March 31, 2012 were $1.6 million compared with $2.5 million for the three months ended March 31, 2011. The three months ended March 31, 2012 balance is primarily related to a $2.0 million retroactive Pennsylvania impact fee discussed in Production and ad valorem taxes. We have elected to report the retroactive portion of the Pennsylvania impact fee as a component of other operating items as the retroactive amount would disproportionately impact comparative periods in future quarters. This amount was offset by miscellaneous gains from inventory sales. The three months ended March 31, 2011 balance primarily related to costs associated with various lawsuits and the former acquisition proposal that terminated in July 2011.

Interest expense

Our interest expense for the three months ended March 31, 2012 increased $1.9 million from the comparable 2011 period. The increase was due primarily to a net increase of interest expense of $2.0 million related to the EXCO Resources Credit Agreement and a $1.4 million decrease of capitalized interest, offset by a $1.3 million decrease in other interest expense related to a $1.2 million payment made in 2011 in connection with the formation of the TGGT credit facility.


	Three months ended March 31,						Quarter to
(in thousands)	2012			2011			quarter change
Interest expense:
2018 Notes	$	14,340		$	14,320		$	20
EXCO Resources Credit Agreement		7,204			5,193			2,011
Amortization and write-off of deferred financing costs on EXCO Resources Credit Agreement		1,005			1,223			(218	)
Amortization of deferred financing costs on 2018 Notes		467			467			—
Capitalized interest		(6,302	)		(7,740	)		1,438
Other		50			1,353			(1,303	)

Total interest expense	$	16,764		$	14,816		$	1,948

Derivative financial instruments

Our objective in entering into derivative financial instruments is to manage our exposure to commodity price and interest rate 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 expenses 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. We expect that our revenues will continue to be significantly impacted in future periods by changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount of future production volumes subject to derivative financial instruments.

The following table presents our realized and unrealized gains and losses from our oil and natural gas derivative financial instruments. Our derivative activity is reported as a component of other income or expenses in our Condensed Consolidated Statements of Operations.


	Three months ended March 31,					Quarter to
(in thousands)	2012		2011			quarter change
Derivative financial instrument activities:
Cash settlements on derivative financial instruments	$	50,145	$	26,935		$	23,210
Non-cash change in fair value of derivative financial instruments		3,720		(23,514	)		27,234

Total derivative financial instrument activities	$	53,865	$	3,421		$	50,444

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


					Quarter to
	Three months ended March 31,				quarter
Realized pricing:	2012		2011		change
Oil per Bbl	$	97.14	$	90.01	$	7.13
Natural gas per Mcf		2.45		4.05		(1.60	)
Natural gas equivalent per Mcfe	$	2.78	$	4.40	$	(1.62	)
Cash settlements on derivatives per Mcfe		1.03		0.73		0.30

Net price per Mcfe, including derivative financial instruments	$	3.81	$	5.13	$	(1.32	)

Our total cash settlements for the three months ended March 31, 2012 increased revenue by $50.1 million, or $1.03 per Mcfe, compared to $26.9 million, or $0.73 per Mcfe, for the same period in 2011. The significant fluctuations between settlements of receipts on our derivative financial instruments demonstrate volatility in prices.

Our non-cash mark-to-market changes in the value of our oil and natural gas derivative financial instruments for the three months ended March 31, 2012 resulted in gains of $3.7 million compared to losses of $23.5 million for the same period in the prior year. The significant fluctuation was, again, attributable to high volatility in the prices for oil and natural gas between each of the periods. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

While the percentage of expected production covered by derivative financial instruments is less than we have historically covered, we expect to continue our comprehensive derivative financial instrument program as part of our overall acquisition and financing strategy designed to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure.

Income taxes

Our effective income tax rate for the three months ended March 31, 2012 and 2011 was zero due to current operating losses due primarily to ceiling test write-downs, which created deferred tax assets. These deferred tax assets have been fully reserved with valuation allowances. Our estimated accumulated valuation allowance as of March 31, 2012 is approximately $482.1 million and can be used against future deferred tax benefits. We will continue to recognize deferred tax valuation allowances until the realization of deferred benefits become more likely than not. The effective income tax rates, excluding the impact of the valuation allowances, for the three months ended March 31, 2012 and 2011 would have been 37.9% and 40.1%, 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 capital market conditions are favorable. Since 2008, when we began to emphasize shale resource plays, we have invested significant development expenditures which exceeded our cash flows from operations during 2010 and 2011. As a result of the current low natural gas price environment, our revised 2012 capital budget has been designed to limit capital spending to approximate our expected cash flows from operations in 2012. In addition, we are evaluating potential transactions which would further enhance our liquidity, including the possible sale of part or all of our interest in TGGT and other assets. Other factors which could impact our liquidity, capital resources and capital commitments in 2012 and future years include the following:

•

the results of our ongoing drilling programs;

•

our ability to effectively reduce our capital expenditure programs in response to continued low natural gas prices;

•

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

•

implementation in 2012 of the Pennsylvania impact fee on non-conventional wells;

•

decreases in the percentage of our production covered by derivative financial instruments, coupled with expiration of higher priced derivative financial instruments;

•

potential acquisitions of oil and natural gas properties;

•

reductions to our borrowing base and our ability maintain compliance with debt covenants as a result of low natural gas prices; and

•

our management of operating and general and administrative costs.

While we believe our existing capital resources, including our cash flow from operations and borrowing capacity under our EXCO Resources Credit Agreement, will be sufficient to conduct our operations through 2012 and into 2013, there are certain risks arising from recent declines in natural gas prices 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 a trailing 12 month computation of EBITDAX. As a result, our ability to maintain compliance with this covenant is negatively impacted when oil and/or natural gas prices decline over an extended period of time. In addition, as a result of the decline in natural gas prices, our borrowing base under the EXCO Resources Credit Agreement was reduced from $1.6 billion to $1.4 billion in April 2012 during our semi-annual borrowing base redetermination. Further borrowing base reductions in future periods may result if natural gas prices do not recover or we sell assets.

In response to the declines in natural gas prices, management has reduced our drilling plans, which will likely reduce our production volumes late in 2012 and into 2013, and has taken measures to reduce operating and administrative expenses. In addition, the volumes of natural gas currently covered by derivative financial instruments declines significantly in 2013. Depending on market conditions, we may enter into additional hedging transactions in 2012. The combination of our reduced borrowing base, lower production volumes and reduced percentages of volumes covered by derivative financial instruments may require us to seek alternative financing arrangements, further reduce costs or sell assets.

Our current capital budget for 2012 is $470.0 million and reflects continued focus on the development of the Marcellus shale, the Haynesville/Bossier shale plays and the Permian area. In Appalachia, our drilling expenditures for the first quarter of 2012 reflect a benefit of $24.9 million from the Appalachia Carry. We expect the remainder of the Appalachia Carry will be fully utilized during 2012.

The following table presents capital expenditures for the first quarter of 2012 and our expected capital expenditures for the remainder of 2012.


	Three months ended March 31,		April - December Forecast		Full Year Forecast
(in thousands)	2012		2012		2012
Capital expenditures:
Development capital	$	141,771	$	248,229	$	390,000
Gas gathering and water pipelines		533		9,467		10,000
Lease acquisitions and seismic		5,676		14,324		20,000
Corporate and other		14,277		35,723		50,000

Total	$	162,257	$	307,743	$	470,000

Operationally, we have reduced our company-wide rig count from 23 at December 31, 2011 to 14 at March 31, 2012 in response to low natural gas prices. We intend to further reduce our rig count during the remainder of 2012 and expect to end 2012 with eight to ten drilling rigs. The rig reductions have been accomplished by a combination of rig contract expirations and early release and termination of rig contracts. Costs incurred for early termination of rig contracts for in the quarter ended March 31, 2012 were approximately $4.6 million. Contracts relating to four of the eight rigs drilling in the DeSoto Parish area are scheduled to expire on September 1, 2012.

In addition, we are expecting to incur rig termination and related fees in Appalachia of approximately $3.6 million in the quarter ending June 30, 2012 for a horizontal drilling rig under contract but not currently being utilized.

We believe our current capital expenditure budget will meet our strategic objectives while maintaining sufficient liquidity. The following table presents our liquidity and financial position as of March 31, 2012 and April 25, 2012:


(in thousands)	March 31, 2012		April 25, 2012
Cash (1)	$	194,613	$	182,644
Drawings under the EXCO Resources Credit Agreement		1,177,500		1,147,500
2018 Notes (2)		750,000		750,000

Total debt		1,927,500		1,897,500

Net debt	$	1,732,887	$	1,714,856

Borrowing base (3)	$	1,600,000	$	1,400,000
Total of unused borrowing base (4)	$	414,478	$	244,478
Unused borrowing base plus cash (1) (4)	$	609,091	$	427,122

(1)	Includes restricted cash of $164.0 million at March 31, 2012 and $138.9 million at April 25, 2012.

(2)	Excludes unamortized bond premium.

(3)	Net of $8.0 million in letters of credit.

(4)	The borrowing base was reduced to $1.4 billion effective April 27, 2012. We are presenting the April 25, 2012 unused borrowing base as if the reduction was effective for this table.

Events affecting liquidity

Our borrowing base, following our April 27, 2012 redetermination, is $1.4 billion with $244.5 million of unused borrowing capacity as of April 25, 2012. The EXCO Resources Credit Agreement also contains provisions which allow us to incur up to an additional $750.0 million of unsecured senior note indebtedness on or before November 1, 2012. The next regularly scheduled borrowing base redetermination is in October 2012.

Although weaknesses in natural gas prices continue, 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. We expect the natural gas markets to continue to experience an extended period of low prices due to excess supply. Accordingly, we are carefully monitoring our capital budget and may implement further drilling rig reductions as required, or sell assets to provide additional liquidity.

Historical sources and uses of funds

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


	Three months ended March 31,
(amounts in thousands)	2012			2011
Cash flows provided by operating activities	$	145,123		$	79,073
Cash flows provided by (used in) investing activities		(167,888	)		146,461
Cash flows provided by (used in) financing activities		21,339			(261,235	)

Net decrease in cash	$	(1,426	)	$	(35,701	)

Our primary sources of cash in the first quarter of 2012 were cash flows from operations and borrowings under the EXCO Resources Credit Agreement.

Cash flows from 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 and natural gas production, including settlement proceeds or payments related to our oil and natural gas derivatives, (iii) operating costs of our oil and natural gas properties, (iv) costs of our general and administrative activities and (v) interest expense and other financing related costs. Our cash flows from operating activities have historically been impacted by fluctuations in oil and natural gas prices and our production volumes. The prolonged decline in natural gas prices over the last two years has had a significant negative impact on our cash flows from operating activities, with the realized average price per Mcfe, including net derivative settlement proceeds, declining 25.7% over the last four quarters.

Net cash provided by operating activities for the three months ended March 31, 2012 was $145.1 million compared with $79.1 million for the three months ended March 31, 2011. The 83.5% increase in the current quarter is primarily attributable to the higher settlement proceeds on our derivatives and favorable working capital conversions, offset by lower average prices received. As of April 25, 2012, our cash and cash equivalent balance was $43.7 million and our restricted cash account, which is used for Haynesville/Bossier shale development operations, was $138.9 million.

Investing activities

Our investing activities consist primarily of drilling and development expenditures, capital contributions to our joint ventures, and acquisitions. Our recent acquisitions have been focused primarily on undeveloped shale acreage in our core areas and have been funded primarily with borrowings under the EXCO Resources Credit Agreement. Future acquisitions are dependent on oil and natural gas prices, availability of attractive acreage and availability of borrowing capacity under the EXCO Resources Credit Agreement or from other capital sources.

For the quarter ended March 31, 2012, our cash flows used in investing activities were $167.9 million, compared with $146.5 million of cash flows provided by investing activities for the quarter ended March 31, 2011, which was favorably impacted by a $125.0 million return of capital distribution from TGGT and receipt of $229.7 million from BG Group for its 50% share of an acquisition in our Appalachia area.

Credit agreement and long-term debt

As of April 25, 2012, we had total debt outstanding of approximately $1.9 billion, which consisted of borrowings under the EXCO Resources Credit Agreement of $1.1 billion and $750.0 million under the 2018 Notes. Terms and conditions of each of the debt obligations are discussed below. Our ability to borrow from sources other than the EXCO Resources Credit Agreement is subject to certain restrictions imposed by our lenders and the indenture governing the 2018 Notes. These agreements contain limitations and restrictions on incurring additional indebtedness and pledging our assets.

EXCO Resources Credit Agreement

At March 31, 2012, the EXCO Resources Credit Agreement had a borrowing base of $1.6 billion and outstanding indebtedness of $1.2 billion. On April 27, 2012, following the completion of our semi-annual redetermination of our borrowing base, we entered into the Sixth Amendment to the EXCO Resources Credit Agreement with the lenders in the bank syndicate. The Sixth Amendment provided for the following changes to the EXCO Resources Credit Agreement:

•

reduced our borrowing base from $1.6 billion to $1.4 billion;

•

increased the maximum ratio of consolidated funded debt to consolidated EBITDAX (as defined in the agreement) to 4.5 to 1.0 from 4.0 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2012;

•

increased the interest rate by 25 bps such that rates now range from LIBOR plus 175 bps to LIBOR plus 275 bps or from ABR plus 75 bps to ABR plus 175 bps, depending on borrowing base usage; and

•

provides for asset sale procedures for sales of oil and natural gas properties or other material assets, including our interest in TGGT Holdings, LLC, whereby the proceeds from asset sales (over a minimum threshold) will be used to pay down the outstanding debt balance under the credit agreement and will also reduce the borrowing base. The borrowing base reduction will be equal to the borrowing base value assigned to the assets sold (if any) plus cash proceeds in excess of the borrowing base value aggregating up to $200 million.

As of April 27, 2012, we have $244.5 million of available borrowing capacity under the EXCO Resources Credit Agreement. The majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement, except those subsidiaries which are jointly held with BG Group. The EXCO Resources Credit Agreement permits certain investments, loans and advances to the unrestricted subsidiaries that are jointly held with BG Group. The EXCO Resources Credit Agreement matures on April 1, 2016 and has regularly scheduled semi-annual borrowing base redeterminations each April and October, with EXCO and the lenders having the right to request interim unscheduled redeterminations in certain circumstances.

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 EXCO Resources Credit Agreement, of our oil and natural gas properties evaluated by the lenders for purposes of establishing our borrowing base. We are permitted to have derivative financial instruments covering no more than 100% of the forecasted production from total Proved Reserves (as defined in the agreement) during the first two years of the forthcoming five year period, 90% of the forecasted production from total Proved Reserves for any month during the third year of the forthcoming five year period and 85% of the forecasted production from total Proved Reserves during the fourth and fifth year 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. Pursuant to the amendment, we may declare and pay cash dividends on our common stock in an amount not to exceed $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 borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under our 2018 Notes.

Based on a one month LIBOR of 0.2% on April 25, 2012, we would incur an interest rate of 2.7% on any new indebtedness we may incur under the EXCO Resources Credit Agreement.

As of March 31, 2012, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, as amended, which requires that we:

•

maintain a consolidated current ratio (as defined in the 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 (as defined in the agreement) to consolidated EBITDAX (as defined in the agreement) to be greater than 4.5 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2012.

The foregoing description is not complete and is qualified in its entirety by the EXCO Resources Credit Agreement.

2018 Notes

As of March 31, 2012 and April 25, 2012, we had outstanding $750.0 million aggregate principal amount of 7.5% senior unsecured notes maturing on September 15, 2018. The 2018 Notes are guaranteed on a senior unsecured basis by a majority of EXCO’s subsidiaries, with the exception of certain non-guarantor subsidiaries and our jointly-held equity investments with BG Group. Our equity investments with BG Group, other than OPCO, are designated as unrestricted subsidiaries under the indenture governing the 2018 Notes. The unamortized discount on the 2018 Notes at March 31, 2012 was $9.4 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $673.1 million on March 31, 2012.

Interest is payable on the on the 2018 Notes semi-annually in arrears on March 15 and September 15 of each year, beginning on March 15, 2011.

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 (over $50.0 million per annum) or redeem, repurchase or retire our capital stock or subordinated debt;

•

make certain investments;

•

create liens on our assets;

•

enter into sale/leaseback transactions;

•

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

•

engage in transactions with our affiliates;

•

transfer or issue shares of stock of subsidiaries;

•

transfer or sell assets; and

•

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

Derivative financial instruments

We use oil and natural gas derivatives and financial risk management instruments to manage our exposure to commodity price and interest rate fluctuations. We do not designate these instruments as hedging instruments for financial accounting purposes and, accordingly, we recognize the change in the respective instruments’ fair value currently in earnings, as a gain or loss on oil and natural gas derivatives and interest expense on financial risk management instruments. Recent financial reform legislation has addressed derivative financial instruments, including the possibility of requiring the posting of cash collateral for certain derivative parties. The definitions and specific requirements of this legislation are yet to be defined and we cannot presently quantify the impact to us, if any.

Oil and natural gas derivatives

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 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. As of March 31, 2012, we had derivative financial instrument contracts 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 2012		20,020	$	5.27		137	$	98.05
Q3 2012		20,240		5.27		138		98.05
Q4 2012		20,240		5.27		138		98.05
2013		5,475		5.99		365		99.96

Off-balance sheet arrangements

As of March 31, 2012, we had no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments


	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
Long-term debt - 2018 Notes (1)	$	—	$	—	$	—	$	750,000	$	750,000
Long-term debt - EXCO Resources Credit Agreement (2)		—		—		1,177,500		—		1,177,500
Firm transportation services (3)		93,408		185,290		180,749		346,462		805,909
Other fixed commitments (4)		37,566		17,558		11,195		1,250		67,569
Drilling contracts		47,812		14,972		—		—		62,784
Operating leases and other		12,947		23,893		4,506		—		41,346

Total contractual obligations (5)	$	191,733	$	241,713	$	1,373,950	$	1,097,712	$	2,905,108

(1)	The 2018 Notes are due on September 15, 2018. The annual interest obligation is $56.3 million.

(2)	The EXCO Resources Credit Agreement, as amended, matures on April 1, 2016. The interest is payable at LIBOR plus 175 bps to LIBOR plus 275 bps, or from ABR plus 75 bps to ABR plus 175 bps, depending on borrowing base usage.

(3)	Firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on a shippers’ pipeline. Whether or not EXCO delivers the minimum quantity, we pay the fees as if the quantities were delivered.

(4)	Other fixed commitments are primarily related to completion service contracts.

(5)

Excludes commitments of our equity method investees, TGGT and OPCO, as neither EXCO nor any of its subsidiaries are guarantors of these commitments. TGGT’s commitments, which consist primarily of compression equipment and office leases, total $8.9 million. OPCO’s commitments, which consist primarily of firm transportation contracts, drilling contracts and completion services, total $84.2 million.

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 and interest rate 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.

Pricing for oil and natural gas is volatile. 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 currently in earnings.

Our major 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.

The following table sets forth our oil and natural gas derivative financial instruments measured at fair value as of March 31, 2012.


(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at March 31, 2012
Natural gas:
Swaps:
Remainder of 2012		60,500	$	5.27	$	167,304
2013		5,475		5.99		13,626

Total natural gas		65,975				180,930


Oil:
Swaps:
Remainder of 2012		413		98.05		(2,666	)
2013		365		99.96		(1,308	)

Total oil		778				(3,974	)


Total oil and natural gas derivatives					$	176,956

At March 31, 2012, the average forward NYMEX oil prices per Bbl for the remainder of 2012 and for 2013 were $104.54 and $103.59 respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2012 and for 2013 were $2.50 and $3.47, respectively. Our reported earnings and assets or liabilities for derivative financial instruments will continue to be subject to significant fluctuations in value due to price volatility.

Realized gains or losses from the settlement of our oil and natural gas derivatives are recorded in our financial statements as gains or losses in other income or loss. For example, using the oil swaps in place as of March 31, 2012, for the remainder of 2012, if the settlement price exceeds the actual weighted average strike price of $98.05 per Bbl, then a reduction in other income would be recorded for the difference between the settlement price and $98.05 per Bbl, multiplied by the hedged volume of 413 Mbbls. Conversely, if the settlement price is less than $98.05 per Bbl, then an increase in other income would be recorded for the difference between the settlement price and $98.05 per Bbl, multiplied by the hedged volume of 413 Mbbls. For example, for a hedged volume of 413 Mbbls, if the settlement price is $99.05 per Bbl then other income would decrease by $0.4 million. Conversely, if the settlement price is $97.05 per Bbl, other income would increase by $0.4 million.

Interest rate risk

At March 31, 2012, our exposure to interest rate changes related primarily to borrowings under the EXCO Resources Credit Agreement and interest earned on our short-term investments. The interest rate is fixed at 7.5% on the 2018 Notes. Interest is payable on borrowings under the EXCO Resources Credit Agreement based on a floating rate as more fully described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our liquidity, capital resources and capital commitments.” At March 31, 2012, we had approximately $1.2 billion in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% change in interest rates of 100 bps based on the variable borrowings as of March 31, 2012 would result in an increase or decrease in our interest expense of $11.8 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. This evaluation included consideration of various processes and procedures 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.

Based upon this evaluation, our principal executive officer and principal financial officer concluded that, as of March 31, 2012, our disclosure controls and procedures were effective.

Prior to March 31, 2012, our management concluded that our disclosure controls and procedures were not effective due to a material weakness related to processes and procedures over the computation of the limitation on capitalized costs, which failed to identify that the computation did not appropriately consider income tax effects. Management believes that it has taken the appropriate remediation steps, including enhanced review and approval controls regarding the computation and the material weakness no longer exists.

Changes in control over financial reporting. During the quarter ended March 31, 2012, we implemented a more comprehensive review of the ceiling test computation and took specific remedial actions including additional reviews, methodologies, procedures and approvals of the ceiling test computation and enhanced coordination between our accounting and income tax staff. There were no additional changes in EXCO’s internal control over financial reporting that occurred during the quarter ended March 31, 2012 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.

Under a Consent Agreement and Final Order, or CAO, dated December 22, 2011, between OPCO and the U.S. Environmental Protection Agency, or the EPA, OPCO agreed to pay a fine of $159,624 to settle allegations related to its compliance with SDWA permitting requirements at a well site in Clearfield County, Pennsylvania. EXCO and BG Group each own 50% of OPCO, which is the joint operator of our Appalachia JV. The EPA determined that OPCO failed to cease injection operations at the well site once a loss of mechanical integrity became evident, failed to give advance notice to the EPA of the reworking of the well site in July and August 2011 and failed to give advance notice to the EPA of a planned mechanical integrity test. Additionally, the EPA cited OPCO for operating the well during March, April and May 2010 at a pressure of 3,250 psi, which exceeded the SDWA permit limitation of 3,240 psi. Under the CAO, OPCO agreed to take certain corrective measures, including but not limited to restoring the well’s mechanical integrity or plugging the well by June 1, 2012. OPCO signed the CAO on December 22, 2011 and the CAO was finalized by the EPA on March 30, 2012.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Issuer repurchases of ordinary shares

The following table details our repurchase of common shares for the three months ended March 31, 2012:


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 (1)
January 1 - January 31, 2012		0	$	0.00		0	$	192.5 million
February 1 - February 29, 2012		0	$	0.00		0	$	192.5 million
March 1 - March 31, 2012		0	$	0.00		0	$	192.5 million

Total		0	$	0.00		0

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

Item 5.

Other Information

On April 27, 2012, EXCO entered into that certain Sixth Amendment to Credit Agreement by and among EXCO, as borrower, certain of its subsidiaries, as guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders named therein. The Sixth Amendment decreased the borrowing base under the EXCO Resources Credit Agreement from $1.6 billion to $1.4 billion. In addition, the interest rate was increased by 25 basis points, or bps, and now ranges from LIBOR plus 175 bps to LIBOR plus 275 bps depending upon borrowing base usage. The Alternate Base Rate, or ABR, pricing alternative was also increased by 25 bps and now ranges from ABR plus 75 bps to ABR plus 175 bps depending upon borrowing base usage.

The Sixth Amendment further provides that the ratio of Consolidated Funded Indebtedness (as defined in the EXCO Resources Credit Agreement) to Consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) may not be greater than 4.5 (formerly 4.0) to 1.0 at the end of any fiscal quarter ending on or after March 31, 2012. In addition, the Sixth Amendment provides that if EXCO or any of its restricted subsidiaries disposes of any oil and natural gas properties (other than dispositions permitted under Section 7.03(a)(vii) of the EXCO Resources Credit Agreement) or any other material assets (including its equity interest in TGGT Holdings, LLC) after April 27, 2012, then 100% of the Net Cash Proceeds (as defined in the EXCO Resources Credit Agreement) of such disposition shall be used to reduce indebtedness under the EXCO Resources Credit Agreement, with a corresponding reduction in the borrowing base to the extent of the borrowing base value assigned to the divested assets, until such time as the aggregate amount of the Net Cash Proceeds used to reduce the indebtedness under the EXCO Resources Credit Agreement is equal to or greater than the sum of (i) the borrowing base value assigned to such divested assets and (ii) $200,000,000.

The foregoing description is not complete and is qualified in its entirety by the Sixth Amendment, which is filed herewith and incorporated by reference herein.

Item 6.

Exhibits

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

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: May 2, 2012	By:	/s/ Douglas H. Miller
		Douglas H. Miller
		Chairman and Chief Executive Officer

	By:	/s/ Stephen F. Smith
		Stephen F. Smith
		President and Chief Financial Officer

INDEX TO EXHIBITS


Exhibit Number		Description of Exhibits

2.1		Membership Interest Transfer Agreement, dated as of May 9, 2010, 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.

2.2		First Amendment to Membership Interest Transfer Agreement, dated as of June 1, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

2.3		Second Amendment to Membership Interest Transfer Agreement, dated as of June 30, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

2.4		Amendment to Membership Interest Transfer Agreement, dated as of November 24, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

2.5		Fourth Amendment to Membership Interest Transfer Agreement, dated as of January 6, 2011, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

2.6		Fifth Amendment to Membership Interest Transfer Agreement, dated as of January 13, 2011, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

2.7		Sixth Amendment to Membership Interest Transfer Agreement, dated as of March 24, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on May 4, 2011 and incorporated by reference herein.

2.8		Seventh Amendment to Membership Interest Transfer Agreement, dated as of June 16, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q filed on August 3, 2011 and incorporated by reference herein.

2.9		Asset Purchase Agreement, dated December 15, 2010, among EXCO Holding (PA), Inc., Chief Oil & Gas LLC, Chief Exploration & Development LLC and Radler 2000 Limited Partnership, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 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, dated March 4, 2009 and filed on March 6, 2009 and incorporated by reference herein.

3.4		Statement of Designation of Series A-l 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., 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.

3.5		Statement of Designation of Series A-2 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., 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.

3.6		Statement of Designation of Series B 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., 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.



3.7		Statement of Designation of Series C 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., 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.

3.8		Statement of Designation of Series A-l Hybrid Preferred Stock of EXCO Resources, Inc., 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.

3.9		Statement of Designation of Series A-2 Hybrid Preferred Stock of EXCO Resources, Inc., 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.

3.10		Statement of Designation of Series A Junior Participating Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 12, 2011 and filed on January 13, 2011 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		Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Amendment No. 2 to the Form S-l (File No. 333-129935), filed on January 27, 2006 and incorporated by reference herein.

4.4		First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-l (File No. 333-129935), filed on January 6, 2006 and incorporated by reference herein.

10.1		Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, 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. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, 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. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, 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. 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, 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.*



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		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.

10.13		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.

10.14		Amended and Restated Limited Liability Company Agreement of TGGT Holdings, LLC, dated August 14, 2009, 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		First Amendment to Amended and Restated Limited Liability Company Agreement of TGGT Holdings, LLC, dated January 31, 2011, 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		Membership Interest Transfer Agreement, dated as of May 9, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.22		First Amendment to Membership Interest Transfer Agreement, dated as of June 1, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.

10.23		Second Amendment to Membership Interest Transfer Agreement, dated as of June 30, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

10.24		Amendment to Membership Interest Transfer Agreement, dated as of November 24, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

10.25		Fourth Amendment to Membership Interest Transfer Agreement, dated as of January 6, 2011, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

10.26		Fifth Amendment to Membership Interest Transfer Agreement, dated as of January 13, 2011, between EXCO Holding (PA), Inc. and BG US Production Company, 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.

10.27		Sixth Amendment to Membership Interest Transfer Agreement, dated as of March 24, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on May 4, 2011 and incorporated by reference herein.

10.28		Seventh Amendment to Membership Interest Transfer Agreement, dated as of June 16, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 3, 2011 and incorporated by reference herein.

10.29		Guaranty, dated May 9, 2010, by BG Energy Holdings Limited in favor of EXCO Holding (PA), Inc., EXCO Production Company (PA), LLC and EXCO Production Company (WV), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

10.30		Guaranty, dated May 9, 2010, by EXCO Resources, Inc. in favor of BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.

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

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

10.33		Credit Agreement, dated as of April 30, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Book runner and Lead Arranger, Wells Fargo Securities, LLC, as Co-Lead Arranger, Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 16, 2010 and filed on July 22, 2010 and incorporated by reference herein.



10.34		First Amendment to Credit Agreement, dated as of July 16, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 16, 2010 and filed on July 22, 2010 and incorporated by reference herein.

10.35		Second Amendment to Credit Agreement, dated as of September 15, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, and Wells Fargo Bank, National Association, as Co-Documentation Agent, 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.

10.36		Third Amendment to Credit Agreement, dated as of April 1, 2011, among EXCO Resources, Inc., 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 Current Report on Form 8-K, dated April 1, 2011 and filed on April 4, 2011 and incorporated by reference herein.

10.37		Fourth Amendment to Credit Agreement, dated as of November 8, 2011, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2011 and filed on November 9, 2011 and incorporated by reference herein.

10.38		Fifth Amendment to Credit Agreement, dated as of November 8, 2011, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 8, 2011 and filed on November 9, 2011 and incorporated by reference herein.

10.39		Sixth Amendment to Credit Agreement, dated as of April 27, 2012, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated April 27, 2012 and filed on April 27, 2012, filed herewith.

10.40		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.

10.41		Credit Agreement, dated January 31, 2011, by and among TGGT Holdings, LLC, its subsidiaries, as borrowers (or guarantor as to one TGGT subsidiary), JPMorgan Chase Bank, N.A., as administrative agent, J.P. Morgan Securities Inc., as sole bookrunner and co-lead arranger, BNP Paribas, Citibank, N.A., The Royal Bank of Scotland PLC and Wells Fargo Securities, LLC, as co-lead arrangers, and the lenders named therein, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated by reference herein.

10.42		First Amendment to Credit Agreement, dated January 25, 2012, by and among TGGT Holdings, LLC, TGG Pipeline, Ltd. And Talco Midstream Assets, Ltd., as Borrowers, TGGT GP Holdings, LLC and certain subsidiaries of Borrowers, as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, J.P. Morgan Securities LLC, as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Securities, LLC, Bank of America, N.A., BMO Harris Financing, Inc., Royal Bank of Canada, Morgan Stanley Senior Funding, Inc., UBS Loan Finance LLC and The Royal Bank of Scotland plc, as Co-Lead Arrangers, and the lenders party thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated January 25, 2012 and filed on January 31, 2012 and incorporated by reference herein.

10.43		EXCO Resources, Inc. Retention Bonus Plan, dated August 4, 2011, 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.*



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

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

32.1		Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief 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.

Furnished with this report. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.