Exco Resources (EXCO) 10-Q 2011 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2011

OR

¨ 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):

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

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 28, 2011 was 213,815,309.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at March 31, 2011 and December 31, 2010	3
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2011 and 2010	5
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2010	6
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Three Months Ended March 31, 2011 and 2010	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	46
PART II.	OTHER INFORMATION	47
Item 1.	Legal Proceedings	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	47
Item 6.	Exhibits	47
	Signatures	48
	Index to Exhibits	49

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	March 31, 2011			December 31, 2010
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	8,528		$	44,229
Restricted cash		150,592			161,717
Accounts receivable, net:
Oil and natural gas		100,999			80,740
Joint interest		102,113			104,358
Interest and other		27,631			35,594
Inventory		7,075			7,876
Derivative financial instruments		58,253			73,176
Other		20,643			12,770
Total current assets		475,834			520,460
Equity investments		264,978			379,001
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		824,686			599,409
Proved developed and undeveloped oil and natural gas properties		2,649,345			2,370,962
Accumulated depletion		(1,375,536	)		(1,312,216	)
Oil and natural gas properties, net		2,098,495			1,658,155
Gas gathering assets		158,741			157,929
Accumulated depreciation and amortization		(26,909	)		(24,772	)
Gas gathering assets, net		131,832			133,157
Office, field, and other equipment, net		41,569			43,149
Deferred financing costs, net		29,014			30,704
Derivative financial instruments		19,818			23,722
Goodwill		218,256			218,256
Deposits on acquisitions		0			464,151
Other assets		6,664			6,665
Total assets	$	3,286,460		$	3,477,420

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share and share data)	March 31, 2011			December 31, 2010
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	175,687		$	152,999
Revenues and royalties payable		140,811			108,830
Accrued interest payable		3,311			18,983
Current portion of asset retirement obligations		1,279			900
Income taxes payable		211			211
Derivative financial instruments		6,508			3,775
Total current liabilities		327,807			285,698
Long-term debt		1,328,526			1,588,269
Deferred income taxes		0			0
Derivative financial instruments		6,153			4,200
Asset retirement obligations and other long-term liabilities		58,653			58,701
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; authorized shares - 10,000,000; none issued and outstanding		0			0
Common stock, $0.001 par value; 350,000,000 authorized shares; 214,286,651 shares issued and 213,747,430 shares outstanding at March 31, 2011; 213,736,266 shares issued and 213,197,045 shares outstanding at December 31, 2010		214			214
Additional paid-in capital		3,162,888			3,151,513
Accumulated deficit		(1,590,302	)		(1,603,696	)
Treasury stock, at cost; 539,221 at March 31, 2011 and December 31, 2010		(7,479	)		(7,479	)
Total shareholders’ equity		1,565,321			1,540,552
Total liabilities and shareholders’ equity	$	3,286,460		$	3,477,420

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended March 31,
(in thousands, except per share data)	2011			2010
Revenues:
Oil and natural gas	$	161,228		$	130,994
Costs and expenses:
Oil and natural gas production		24,934			27,058
Gathering and transportation		17,286			11,113
Depreciation, depletion and amortization		67,930			38,818
Accretion of discount on asset retirement obligations		857			1,089
General and administrative		23,423			26,419
Other operating items		2,167			(407	)
Total costs and expenses		136,597			104,090
Operating income		24,631			26,904
Other income (expense):
Interest expense		(14,816	)		(10,634	)
Gain on derivative financial instruments		3,421			99,149
Other income		160			60
Equity income		8,545			89
Total other income (expense)		(2,690	)		88,664
Income before income taxes		21,941			115,568
Income tax expense		0			0
Net income	$	21,941		$	115,568
Earnings per common share:
Basic
Net income	$	0.10		$	0.54
Weighted average common shares outstanding		213,531			212,086
Diluted
Net income	$	0.10		$	0.54
Weighted average common and common equivalent shares outstanding		217,110			215,666

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three months ended March 31,
(in thousands)	2011			2010
Operating Activities:
Net income	$	21,941		$	115,568
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		67,930			38,818
Stock option compensation expense		2,668			4,609
Accretion of discount on asset retirement obligations		857			1,089
Income from equity investments		(8,545	)		(89	)
Non-cash change in fair value of derivatives		23,514			(24,120	)
Cash settlements of assumed derivatives		—			907
Deferred income taxes		0			0
Amortization of deferred financing costs; discount on the 2018 Notes and premium on the 2011 Notes		1,947			(90	)
Effect of changes in:
Accounts receivable		(15,296	)		(40,548	)
Other current assets		(2,813	)		(1,680	)
Accounts payable and other current liabilities		(13,130	)		(3,161	)
Net cash provided by operating activities		79,073			91,303
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(199,610	)		(124,223	)
Property acquisitions		(506,833	)		(10,943	)
Restricted cash		11,125			(11,079	)
Deposit on pending acquisitions		464,151			0
Investment in equity investments		(162	)		(44,500	)
Return of investment in equity investments		125,000			0
Proceeds from disposition of property and equipment		259,103			66,925
Advances to Appalachia JV		(5,063	)		—
Other		(1,250	)		—
Net cash provided by (used in) investing activities		146,461			(123,820	)
Financing Activities:
Borrowings under credit agreements		40,000			39,960
Repayments under credit agreements		(300,000	)		(24,981	)
Proceeds from issuance of common stock		7,312			4,206
Payment of common stock dividends		(8,547	)		(6,364	)
Settlements of derivative financial instruments with a financing element		—			(907	)
Net cash provided by (used in) financing activities		(261,235	)		11,914
Net decrease in cash		(35,701	)		(20,603	)
Cash at beginning of period		44,229			68,407
Cash at end of period	$	8,528		$	47,804
Supplemental Cash Flow Information:
Cash interest payments	$	32,809		$	21,041
Income tax payments	$	—		$	—
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	1,380		$	1,105
Capitalized interest	$	7,740		$	2,915
Issuance of common stock for director services	$	15		$	9

See accompanying notes.

6

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Common Stock				Treasury Stock						Additional paid-in		Retained earnings			Total shareholders’
(in thousands)	Shares		Amount		Shares			Amount			capital		(deficit)			equity
Balance at December 31, 2009		211,905	$	212		0		$	0		$	3,105,238	$	(2,245,862	)	$	859,588
Issuance of common stock		334		0								4,215					4,215
Share-based compensation												5,714					5,714
Common stock dividends														(6,364	)		(6,364	)
Net income														115,568			115,568
Balance at March 31, 2010		212,239	$	212		0		$	0		$	3,115,167	$	(2,136,658	)	$	978,721
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

See accompanying notes.

7

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 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, respectively.

Our primary 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. Future acquisitions remain targeted on supplementing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. 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. In order to accelerate our development efforts, we have entered into four separate joint ventures with affiliates of BG Group, plc, or BG Group. A brief description of each joint venture follows:

• 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 EOC, serving as operator. 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 $400.0 million, or the East Texas/North Louisiana Carry. During the first quarter of 2011, we utilized the remaining balance of the East Texas/North Louisiana Carry. We report the operating results and financial position of the East Texas/North Louisiana JV using proportional consolidation.

• A joint venture with BG Group in which we both 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.

• A 50/50 joint venture with BG Group covering our shallow producing assets and prospective Marcellus shale acreage in the Appalachia region, or the Appalachia JV. EXCO and BG Group jointly operate the Appalachia JV operations through a 50/50 owned operating entity, or OPCO, which holds a 0.5% working interest in all of the shallow conventional assets and the deep rights in the Appalachia JV. 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, 2011, the remaining balance of the Appalachia Carry was approximately $110.9 million. We use the equity method to account for our investment in OPCO and proportionally consolidate our 49.75% non-operating interest in the Appalachia area oil and natural gas exploration and development.

• A jointly-owned midstream company, or the Appalachia Midstream JV, to provide take-away capacity in the Marcellus shale. We use the equity method to account for our 50% investment in the Appalachia Midstream JV.

We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays, and exploiting our multi-year inventory of development drilling locations. We also continue to pursue acquisitions in the core areas of our shale plays. We employ the use of debt along with a comprehensive derivative financial instrument program to support our strategy. These approaches enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investments and manage our capital structure.

On October 29, 2010, our Chairman and Chief Executive Officer, Douglas H. Miller presented a letter to our board of directors indicating an interest in acquiring all of the outstanding shares of our stock not already owned by Mr. Miller for a cash purchase price of $20.50 per share. The proposal does not represent a definitive offer and there is no assurance that a definitive offer will be made or accepted, that any agreement will be executed or that any transaction will be consummated.

8

Our board of directors established a special committee on November 4, 2010 comprised of two of our independent directors to, among other things, evaluate and determine the Company’s response to the October 29, 2010 proposal. The special committee retained Kirkland & Ellis LLP and Jones Day as its legal counsel and Barclays Capital, Inc. and Evercore Partners as its financial advisors to assist it in, among other things, evaluating and determining the Company’s response to the proposal. See “Note 16. Acquisition proposal” for further information regarding the proposal.

The accompanying Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010, the Condensed Consolidated Statements of Operations, the Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the three months ended March 31, 2011 and 2010 are for EXCO and its subsidiaries. The condensed consolidated financial statements and related footnotes are presented in accordance with accounting principles generally accepted in the United States of America, or GAAP. All intercompany transactions have been eliminated.

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, 2011 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, 2010, as amended.

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

2. Significant recent activities

Chief Transaction

On December 21, 2010, we funded the acquisition of undeveloped acreage and oil and natural gas properties primarily in the Marcellus shale from Chief Oil & Gas LLC and related parties for approximately $459.4 million, subject to post-closing title adjustments and customary post-closing purchase price adjustments, or the Chief Transaction. The $459.4 million preliminary purchase price was funded into an escrow account pending receipt of a waiver from a third party, which was received on January 11, 2011 and all properties were released to us. BG Group participated in its 50% share of the Chief Transaction and funded $229.7 million to us on February 7, 2011.

Appalachia Transaction

On March 1, 2011, we jointly closed the purchase of additional Marcellus shale properties with BG Group, which also included certain shallow production primarily in Jefferson and Clarion counties in Pennsylvania for $81.1 million ($40.5 million net to us), subject to customary post-closing adjustments, or the Appalachia Transaction.

3. Recent accounting pronouncements

There are no recent accounting pronouncements which we expect would have a significant impact on our financial statements.

4. 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, 2010, as amended.

9

5. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the three months ended March 31, 2011:

(in thousands)
Asset retirement obligation at January 1, 2011	$	50,292
Activity during the three months ended March 31, 2011:
Adjustment to liability due to acquisitions		1,684
Liabilities incurred during the period		456
Liabilities settled during the period		(86	)
Accretion of discount		857
Asset retirement obligations at March 31, 2011		53,203
Less current portion		1,279
Long-term portion	$	51,924

We have no assets that are legally restricted for purposes of settling asset retirement obligations.

6. 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 exploration, exploitation, development and acquisition costs. 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 gas properties, properties under development, and major development projects, collectively totaled $824.7 million and $599.4 million as of March 31, 2011 and December 31, 2010, respectively, and are not subject to depletion. The $225.3 million increase in our unproved properties between December 31, 2010 and March 31, 2011 was due primarily to properties purchased in the Chief Transaction and the Appalachia Transaction. 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. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus acquired proved and unproved leaseholds.

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 period, 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.

10

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, 2011, the trailing twelve month reference price was $83.41 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma and $4.10 per Mmbtu for natural gas at Henry Hub. Each of the aforementioned 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. There were no ceiling test write-downs during the three months ended March 31, 2011 and 2010.

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.

7. 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, 2011 and 2010 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, 2011 and 2010 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 560,486 and 684,952 antidilutive common stock equivalents from the three months ended March 31, 2011 and 2010, 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)	2011		2010
Basic income per common share:
Net income	$	21,941	$	115,568
Shares:
Weighted average number of common shares outstanding		213,531		212,086
Basic income per common share:
Net income per common share	$	0.10	$	0.54
Diluted income per share:
Net income	$	21,941	$	115,568
Shares:
Weighted average number of common shares outstanding		213,531		212,086
Dilutive effect of stock options		3,579		3,580
Weighted average number of common shares and common stock equivalent shares outstanding		217,110		215,666
Diluted income per share:
Net income per common share	$	0.10	$	0.54

8. Stock options

We account for stock options in accordance with FASB ASC Topic 718 for Compensation – Stock Compensation Topic, or ASC 718. As required by ASC 718, the granting of options to our employees under our 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital. Volatility is determined based on the combination of the weighted average volatility of our common stock price and the weighted average volatility from five comparable public companies during the period when we were privately held. Total share-based compensation to be recognized on unvested awards as of March 31, 2011 is $25.0 million over a weighted average period of 1.8 years.

11

The following is a reconciliation of our stock option expense for the three months ended March 31, 2011 and 2010:

	Three months ended March 31,
(in thousands)	2011		2010
General and administrative expense	$	2,585	$	4,259
Lease operating expense		83		350
Total share-based compensation expense		2,668		4,609
Share-based compensation capitalized		1,380		1,105
Total share-based compensation	$	4,048	$	5,714

During the three months ended March 31, 2011, options to purchase 54,000 shares were granted under the 2005 Incentive Plan at $20.16 per share with fair value of $11.32 per share. During the three months ended March 31, 2010, options to purchase 186,700 shares of common stock were granted under the 2005 Incentive Plan at prices ranging from $18.38 to $22.22 per share with fair values ranging from $10.47 to $12.77 per share. The options expire ten years following the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As of March 31, 2011 and December 31, 2010, there were 2,101,300 and 2,068,375 options available for grant under the 2005 Incentive Plan, respectively.

In connection with certain divestitures, in the first quarter of 2010 we accelerated the vesting of a number of employee stock options on the date of the employee’s termination and extended their exercise terms to one year from date of termination. For the three months ended March 31, 2010, we recognized $0.9 million in additional compensation expense related to the modification of option terms, $0.5 million of which would have been recognized over the remaining life of the options had they not been accelerated. The underlying stock price on the dates of modification ranged from $17.54 to $21.23 and the exercise prices of the options accelerated ranged from $7.50 to $24.66.

9. 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 for 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.

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Fair Value of Derivative Financial Instruments

(in thousands)	Balance Sheet location	March 31, 2011			December 31, 2010
Commodity contracts	Derivative financial instruments - Current assets	$	58,253		$	73,176
Commodity contracts	Derivative financial instruments - Long-term assets		19,818			23,722
Commodity contracts	Derivative financial instruments - Current liabilities		(6,508	)		(3,775	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(6,153	)		(4,200	)
Net derivatives		$	65,410		$	88,923

The Effect of Derivative Financial Instruments

		Three months ended March 31,
(in thousands)	Statement of Operations location	2011		2010
Commodity contracts (1)	Gain on derivative financial instruments	$	3,421	$	99,149
Interest rate contracts (2)	Interest income (expense)		—		(45	)
Net gain		$	3,421	$	99,104

(1) Included in these amounts are net cash receipts of $26,935 and $77,047 for the three months ended March 31, 2011 and 2010, respectively.

(2) Included in these amounts are net cash payments of $0 and $2,063 for the three months ended March 31, 2011 and 2010, 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 currently with a corresponding increase or decrease in the balance sheet fair value amounts. Unrealized fair value adjustments included in “Gain (loss) on derivative financial instruments,” which do not impact cash flows, were losses of $23.5 million and gains of $22.1 million for the three months ended March 31, 2011 and 2010, respectively. Unrealized fair value adjustments included in “Interest expense,” which do not impact cash flows, were a gain of $2.0 million for the three months ended March 31, 2010. There was no impact for the three months ended March 31, 2011, as our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of March 31, 2011.

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.

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The following table presents the volume and fair value of our oil and natural gas derivative financial instruments as of March 31, 2011:

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at March 31, 2011
Natural gas:
Swaps:
Remainder of 2011		67,375	$	5.28	$	47,452
2012		53,070		5.37		16,294
2013		5,475		5.99		3,124
Total natural gas		125,920				66,870
Oil:
Swaps:
Remainder of 2011		413		111.32		1,396
2012		275		95.70		(2,856	)
Total oil		688				(1,460	)
Total oil and natural gas derivatives					$	65,410

At December 31, 2010, we had outstanding derivative contracts to mitigate price volatility covering 89,500 Mmcf of natural gas and 822 Mbbls of oil. At March 31, 2011, the average forward NYMEX oil prices per Bbl for the remainder of 2011 and for 2012 were $107.50 and $106.29, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2011 and for 2012 were $4.61 and $5.06, respectively.

Our derivative financial instruments covered 54.7% and 66.4% of our total expected equivalent Mcfe production for the three months ended March 31, 2011 and 2010, respectively.

10. Fair value measurements

We value our derivatives according to FASB ASC Topic 820 for 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 prioritize 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 withinLevel 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, 2011 and December 31, 2010. During the three months ended March 31, 2011, there were no changes in the fair value level classifications.

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	March 31, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	65,410	$	—	$	65,410
	December 31, 2010
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	88,923	$	—	$	88,923

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, (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 PEPL index quotes for our existing basis 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 9. 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 2018 Notes, was $762.2 million with a carrying amount of $739.5 million as of March 31, 2011. The estimated fair value has been calculated based on market quotes.

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11. Long-term debt

Our total debt is summarized as follows:

(in thousands)	March 31, 2011			December 31, 2010
EXCO Resources Credit Agreement	$	589,000		$	849,000
2018 Notes		750,000			750,000
Unamortized discount on 2018 Notes		(10,474	)		(10,731	)
Total debt	$	1,328,526		$	1,588,269

As of March 31, 2011, we had total debt outstanding of approximately $1.3 billion consisting of borrowings under our EXCO Resources Credit Agreement of $589.0 million and the 2018 Notes. Terms and conditions of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

As of March 31, 2011, the EXCO Resources Credit Agreement had a borrowing base of $1.0 billion, with $589.0 million of outstanding indebtedness and $395.5 million of available borrowing capacity. The borrowing base is redetermined semi-annually, with us and the lenders having the right to request interim unscheduled redeterminations in certain circumstances. On April 1, 2011, we entered into the Third Amendment to the EXCO Resources Credit Agreement in conjunction with the regular semi-annual redetermination of the borrowing base and increased the borrowing base from $1.0 billion to $1.5 billion. In addition, the interest rate was reduced by 50 basis points, or bps, and now ranges from LIBOR plus 150 bps to LIBOR plus 250 bps, or from Alternative Base Rate, or ABR, plus 50 bps to ABR plus 150 bps, depending upon borrowing base usage. Our consolidated ratio of funded indebtedness to consolidated EBITDAX (as defined in the agreement), increased by 0.5, so that the ratio can be no greater than 4.0 to 1.0. The maturity date was extended from April 30, 2014 to 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 which $7.5 million has been utilized, of our common stock.

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 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, 2011, 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 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 agreement) to be greater than 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2010.

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

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EOC credit agreement

On April 30, 2010, the EOC credit agreement was consolidated into the EXCO Resources Credit Agreement and, among other things, EOC and certain of its subsidiaries became guarantor subsidiaries under the EXCO Resources Credit Agreement.

2018 Notes

On September 15, 2010 we closed on an underwritten offering of the 2018 Notes and concurrently provided notice to the trustee for our 7 ¹/4% senior notes due January 15, 2011, or the 2011 Notes, in accordance with the indenture to fully redeem all of the $444.7 million in outstanding notes on October 15, 2010. We used a portion of the proceeds from the issuance of the 2018 Notes for the redemption of the 2011 Notes, including accrued interest of $8.1 million from July 15, 2010 to the redemption date. The 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, 2011, $750.0 million in principal was outstanding on our 2018 Notes. The unamortized discount on the 2018 Notes at March 31, 2011 was $10.5 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $762.2 million on March 31, 2011.

Interest is payable 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.

12. Dividends

On March 2, 2011, our Board of Directors approved a first quarter 2011 cash dividend of $0.04 per share. The total cash dividend of $8.5 million was paid on March 31, 2011 to holders of record on March 15, 2011. 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, our 2018 Notes and the approval of EXCO’s Board of Directors.

13. Income taxes

Each quarter we evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws. We apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial operating losses primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties. For the three months ended March 31, 2011, we estimate that we have utilized $8.8 million of our accumulated valuation allowance. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $380.0 million, as of March 31, 2011, 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.

14. Equity investments

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

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We have a 50% ownership in TGGT, which holds interests in midstream assets in East Texas and North Louisiana. During the first quarter of 2011, TGGT closed on its credit facility and used a majority of the proceeds from the initial draw to make a return of capital distribution to both us and BG Group of $250.0 million, $125.0 million net to each partner.

In conjunction with the Appalachia JV, 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 quarter of 2011, EXCO and BG Group each contributed $2.4 million to OPCO, which is equal to OPCO’s 0.5% interest in the 2011 property acquisitions, plus all related working capital items and other fixed assets that will be used to service the properties acquired.

The third equity method investment is 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.

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, 2011		December 31, 2010
Assets
Total current assets	$	147,815	$	120,475
Property and equipment, net		922,371		873,228
Other assets		4,104		6,143
Total assets	$	1,074,290	$	999,846
Liabilities and members’ equity
Total current liabilities	$	146,602	$	145,006
Total long term debt		307,142		—
Total long term liabilities		4,783		10,092
Members’ equity:
Total members’ equity		615,763		844,748
Total liabilities and members’ equity	$	1,074,290	$	999,846
	Three months ended
(in thousands)	March 31, 2011		March 31, 2010
Revenues
Oil and natural gas	$	126	$	—
Midstream		43,096		31,784
Total revenues		43,222		31,784
Costs and expenses:
Oil and natural gas production		161		—
Midstream operating		12,977		25,723
Other expenses		7,092		2,922
Depreciation, depletion, and amortization		6,505		3,699
Total costs and expenses		26,735		32,344
Income before income taxes		16,487		(560	)
Income tax expense		335		67
Net income (loss)	$	16,152	$	(627	)
EXCO’s share of equity income (loss) before amortization	$	8,076	$	(314	)
Amortization of the difference in the historical basis of our contribution	$	469	$	403
EXCO’s share of equity income after amortization	$	8,545	$	89

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(in thousands)	March 31, 2011			December 31, 2010
Equity investments	$	264,978		$	379,001
Basis adjustment (1)		45,755			45,755
Cumulative amortization of basis adjustment (2)		(2,851	)		(2,382	)
EXCO’s 50% interest in equity investments	$	307,882		$	422,374

(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.

15. Share repurchase

On July 19, 2010, we announced a share repurchase program which authorizes us to purchase up to $200.0 million of our common stock. Any repurchases will be made in the open market, in privately negotiated transactions or in structured share repurchase programs, and may be made from time to time and in one or more large repurchases. The program will be conducted in compliance with the SEC’s Rule 10b-18 and applicable legal requirements and shall be subject to market conditions and other factors. EXCO is not obligated to repurchase any common stock, or any particular amount of common stock, and the repurchase program may be modified or suspended at any time at EXCO’s discretion. The repurchases may be funded from available cash or borrowings under the EXCO Resources Credit Agreement.

As of March 31, 2011, we have repurchased a total of 539,221 shares for $7.5 million at an average price of $13.87 per share. The program was suspended as a result of the pending strategic alternatives being evaluated by a special committee of our Board of Directors in connection with the October 29, 2010 proposal from our Chairman and Chief Executive Officer to purchase all of our outstanding common stock that he does not already own.

16. Acquisition proposal

On October 29, 2010, our Chairman and Chief Executive Officer, Douglas H. Miller presented a letter to our board of directors indicating an interest in acquiring all of the outstanding shares of our stock not already owned by Mr. Miller for a cash purchase price of $20.50 per share. The proposal does not represent a definitive offer and there is no assurance that a definitive offer will be made or accepted, that any agreement will be executed or that any transaction will be consummated.

Since November 3, 2010, nine related shareholder derivative lawsuits were filed purportedly on behalf of the Company in state and federal courts in Dallas, Texas alleging claims related to Mr. Miller’s proposal. The lawsuits name as defendants all of the members of our board of directors, and in some of the lawsuits, also name as defendants two of our investors, Oaktree Capital Management, L.P. and Ares Management, LLC. The Company is named as a nominal defendant in each of the cases. The shareholder derivative lawsuits generally allege that our directors have breached their fiduciary duties by failing to implement fair and adequate procedures for the consideration of Mr. Miller’s proposal and by failing to maximize shareholder value. The remaining defendants are alleged to have aided and abetted the purported breaches of fiduciary duty. The plaintiffs seek on behalf of the Company an injunction preventing consummation of Mr. Miller’s proposed transaction, unspecified compensatory damages from the defendants other than the Company, and an award of attorney’s fees and costs.

Also, since November 3, 2010, two putative shareholder class actions have been filed against the Company and all of the members of our board of directors in state district courts in Dallas County, Texas. The purported class actions allege that the Company and our directors breached fiduciary duties allegedly owed to public shareholders by attempting to consummate a transaction based on Mr. Miller’s proposal. The plaintiffs seek unspecified damages, an order rescinding any transaction based on Mr. Miller’s proposal, an accounting from the defendants for any profits or special benefits they may have received, and an award of attorney’s fees and costs.

Our board of directors established a special committee on November 4, 2010 comprised of two independent directors to, among other things, evaluate and determine the Company’s response to the October 29, 2010 proposal and to evaluate the allegations raised in the derivative lawsuits. The special committee retained Kirkland & Ellis LLP and Jones Day as its legal counsel and Barclays Capital, Inc. and Evercore Partners as its financial advisors to assist it in, among other things, evaluating and determining the Company’s response to the proposal.

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All of the state court proceedings have been consolidated into one court and are now proceeding as a consolidated derivative action and a consolidated class action. Separate lead plaintiffs’ counsel have been appointed for the consolidated derivative action and the consolidated direct class action. Currently, there are four lawsuits pending in Texas state and federal courts related to Mr. Miller’s proposal: the consolidated derivative action and consolidated direct class action are pending in state court and two derivative actions are pending in federal court.

On April 18, 2011, the Company and the members of the Board moved to dismiss the consolidated state court derivative action.

On January 12, 2011, in connection with the strategic review process, the Company and the special committee entered into an agreement with Mr. Miller containing customary confidentiality and standstill provisions. The standstill provisions prohibit Mr. Miller from, among other things, acquiring additional shares of EXCO common stock, entering into agreements regarding or soliciting proxies in connection with an acquisition of the Company and seeking to influence the management of the Company in connection with such an acquisition. In addition, the agreement prohibits Mr. Miller from entering into agreements preventing EXCO shareholders from voting in favor of, or tendering their shares in response to, other offers to acquire the Company or preventing financing sources from providing financing to other parties in connection with an acquisition of the Company. The agreement also limits the parties with whom Mr. Miller can enter into financing arrangements. The special committee expects to enter into similar agreements with other parties interested in exploring a possible acquisition of the Company. The agreement also limits the parties with whom Mr. Miller can enter into financing arrangements.

In addition, at the direction of the special committee, on January 12, 2011, the Company adopted a shareholder rights plan, or the Rights Plan, with a one year term. The Rights Plan is intended to enhance the ability of the special committee to conduct a thorough, deliberative process of exploring our strategic alternatives. Under the terms of the rights plan, one right attached to each share of the Company’s common stock that was outstanding as of the close of business on January 24, 2011 and one right will attach to each share issued thereafter prior to the expiration of the rights. The rights will become exercisable (subject to customary exceptions) only if a person or group acquires 10% or more of the Company’s common stock (thereby becoming an “acquiring person”) or commences a tender offer for 10% or more of the Company’s common stock. The plan exempts each holder of 10% or more of the Company’s common stock on the date of the plan’s adoption as long as they do not thereafter acquire an additional 1% or more shares of the Company’s common stock, as well as parties that enter into qualifying standstill agreements with the Company. The special committee may, in its sole discretion, also exempt any transaction from triggering the plan. The rights expire on January 24, 2012.

On January 18, 2011 one derivative plaintiff requested that a state court enjoin the operation of a shareholder rights plan (as discussed in more detail below). The Company opposed this request and, after a hearing, on January 21, 2011 the state court rejected the plaintiff’s motion for an injunction, allowing the implementation of the shareholder rights plan.

On January 13, 2011, the special committee of the board of directors announced that it will explore strategic alternatives to maximize shareholder value, including a potential sale of the Company. As part of a comprehensive process, the special committee stated that it will consider Mr. Miller’s proposal as well as acquisition proposals the special committee may receive from other interested parties and other strategic alternatives potentially available to the Company. There can be no assurance that the special committee’s exploration of strategic alternatives will result in a sale of the Company or any other transaction.

17. Subsequent events

Amendment of the EXCO Resources Credit Agreement

On April 1, 2011, we entered into the Third Amendment to the EXCO Resources Credit Agreement, resulting in an increase of the borrowing base from $1.0 billion to $1.5 billion. In addition, the interest rate under the EXCO Resources Credit Agreement was reduced by 50 bps and now ranges from LIBOR plus 150 bps to LIBOR plus 250 bps, or from ABR plus 50 bps to ABR plus 150 bps, depending upon borrowing base usage. Our consolidated ratio of funded indebtedness to consolidated EBITDAX (as defined in the agreement) increased by 0.5, so that the ratio can be no greater than 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2010. The maturity date was extended from April 30, 2014 to April 1, 2016.

Haynesville shale acquisition

On April 5, 2011, we closed on a $225.2 million acquisition of land, mineral interests and other assets in DeSoto Parish, Louisiana. BG Group has been offered to participate in this acquisition for its 50% share in accordance with contracts covering our East Texas/North Louisiana JV.

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18. Condensed consolidating financial statements

As of March 31, 2011, 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 2018 Notes, with the exception of our equity investment in OPCO. As of March 31, 2011:

• Our equity method investment in OPCO represented $2.7 million of equity method investments and contributed $0.1 million of equity method losses;

• Our interests in jointly held entities with BG Group, with the exception of OPCO, represented $262.3 million of equity method investments, or 8.0% of our total assets and contributed $8.6 million of equity method income; and

• Our non-guarantor, unrestricted subsidiaries that are wholly owned represented approximately 0.5% of our total assets and $4.5 million of liabilities, including trade payables, but excluding intercompany liabilities.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2010 condensed consolidating financial statements have been restated to reflect the consolidation of the EOC credit agreement into the EXCO Resources Credit Agreement, which occurred on April 30, 2010. 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). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of Resources (defined below), and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries. For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from 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.

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EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

March 31, 2011

(in thousands)	Resources			Guarantor subsidiaries			Non-Guarantor subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	50,252		$	(41,724	)	$	—	$	—		$	8,528
Restricted cash		—			150,592			—		—			150,592
Other current assets		71,261			245,432			21		—			316,714
Total current assets		121,513			354,300			21		—			475,834
Equity investment		—			—			264,978		—			264,978
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		31,098			793,588			—		—			824,686
Proved developed and undeveloped oil and natural gas properties		408,573			2,240,772			—		—			2,649,345
Accumulated depletion		(300,099	)		(1,075,437	)		—		—			(1,375,536	)
Oil and natural gas properties, net		139,572			1,958,923			—		—			2,098,495
Gas gathering, office and field equipment, net		29,426			127,790			16,185		—			173,401
Investments in and advances to affiliates		991,526			92,973			—		(1,084,499	)		—
Deferred financing costs, net		29,014			—			—		—			29,014
Derivative financial instruments		11,623			8,195			—		—			19,818
Goodwill		38,100			180,156			—		—			218,256
Other assets		3			6,661			—		—			6,664
Total assets	$	1,360,777		$	2,728,998		$	281,184	$	(1,084,499	)	$	3,286,460
Liabilities and shareholders’ equity
Current liabilities	$	46,734		$	276,621		$	4,452	$	—		$	327,807
Long-term debt, net of current maturities		1,328,526			—			—		—			1,328,526
Deferred income taxes		—			—			—		—			—
Other liabilities		11,902			52,904			—		—			64,806
Payable to parent		(1,591,706	)		1,586,119			5,587		—			—
Total shareholders’ equity		1,565,321			813,354			271,145		(1,084,499	)		1,565,321
Total liabilities and shareholders’ equity	$	1,360,777		$	2,728,998		$	281,184	$	(1,084,499	)	$	3,286,460

22

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2010

(in thousands)	Resources			Guarantor subsidiaries			Non-Guarantor subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	76,763		$	(32,534	)	$	—	$	—		$	44,229
Restricted cash		—			161,717			—		—			161,717
Other current assets		83,913			230,590			11		—			314,514
Total current assets		160,676			359,773			11		—			520,460
Equity investment		—			—			379,001		—			379,001
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		37,818			561,591			—		—			599,409
Proved developed and undeveloped oil and natural gas properties		385,357			1,985,605			—		—			2,370,962
Accumulated depletion		(295,453	)		(1,016,763	)		—		—			(1,312,216	)
Oil and natural gas properties, net		127,722			1,530,433			—		—			1,658,155
Gas gathering, office and field equipment, net		28,837			131,276			16,193		—			176,306
Investments in and advances to affiliates		964,806			92,973			—		(1,057,779	)		—
Deferred financing costs, net		30,704			—			—		—			30,704
Derivative financial instruments		13,665			10,057			—		—			23,722
Goodwill		38,100			180,156			—		—			218,256
Other assets		3			470,813			—		—			470,816
Total assets	$	1,364,513		$	2,775,481		$	395,205	$	(1,057,779	)	$	3,477,420
Liabilities and shareholders’ equity
Current liabilities	$	50,654		$	228,332		$	6,712	$	—		$	285,698
Long-term debt, net of current maturities		1,588,269			—			—		—			1,588,269
Deferred income taxes		—			—			—		—			—
Other liabilities		10,234			52,667			—		—			62,901
Payable to parent		(1,825,196	)		1,821,530			3,666		—			—
Total shareholders’ equity		1,540,552			672,952			384,827		(1,057,779	)		1,540,552
Total liabilities and shareholders’ equity	$	1,364,513		$	2,775,481		$	395,205	$	(1,057,779	)	$	3,477,420

23

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		$	—		$	—		$	161,228
Costs and expenses:
Oil and natural gas production		4,287			20,357			290			—			24,934
Gathering and transportation		—			17,286			—			—			17,286
Depreciation, depletion and amortization		6,566			60,993			371			—			67,930
Accretion of discount on asset retirement obligations		101			756			—			—			857
General and administrative		4,716			18,707			—			—			23,423
Other operating items		2,616			553			(1,002	)		—			2,167
Total costs and expenses		18,286			118,652			(341	)		—			136,597
Operating income		5,100			19,190			341			—			24,631
Other income (expense):
Interest expense		(13,564	)		(1,252	)		—			—			(14,816	)
Gain (loss) on derivative financial instruments		3,601			(180	)		—			—			3,421
Other income		84			76			—			—			160
Equity income		—			—			8,545			—			8,545
Equity in earnings of subsidiaries		26,720			—			—			(26,720	)		—
Total other income (expense)		16,841			(1,356	)		8,545			(26,720	)		(2,690	)
Income (loss) before income taxes		21,941			17,834			8,886			(26,720	)		21,941
Income tax expense		—			—			—			—			—
Net income (loss)	$	21,941		$	17,834		$	8,886		$	(26,720	)	$	21,941

24

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended March 31, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	17,645		$	112,668		$	681		$	—		$	130,994
Costs and expenses:
Oil and natural gas production		3,956			23,154			(52	)		—			27,058
Gathering and transportation		—			10,995			118			—			11,113
Depreciation, depletion and amortization		7,150			31,440			228			—			38,818
Accretion of discount on asset retirement obligations		83			1,006			—			—			1,089
General and administrative		7,645			18,774			—			—			26,419
Other operating items		(602	)		195			—			—			(407	)
Total costs and expenses		18,232			85,564			294			—			104,090
Operating income (loss)		(587	)		27,104			387			—			26,904
Other income (expense):
Interest expense		(7,074	)		(3,560	)		—			—			(10,634	)
Gain on derivative financial instruments		30,854			68,295			—			—			99,149
Other income (expense)		6,174			(6,114	)		—			—			60
Equity income		—			—			89			—			89
Equity in earnings of subsidiaries		86,201			—			—			(86,201	)		—
Total other income (expense)		116,155			58,621			89			(86,201	)		88,664
Income (loss) before income taxes		115,568			85,725			476			(86,201	)		115,568
Income tax expense		—			—			—			—			—
Net income (loss)	$	115,568		$	85,725		$	476		$	(86,201	)	$	115,568

25

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2011

				Guarantor			Non-Guarantor
(in thousands)	Resources			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	18,448		$	59,468		$	1,157		$	—	$	79,073
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment and property acquisitions		(17,463	)		(685,916	)		(3,064	)		—		(706,443	)
Restricted cash		—			11,125			—			—		11,125
Deposit on pending acquisitions		—			464,151			—			—		464,151
Investment in equity investments		—			(162	)		—			—		(162	)
Return of investment in equity investments		—			125,000			—			—		125,000
Proceeds from disposition of property and equipment		39			259,064			—			—		259,103
Advances to Appalachia JV		—			(5,063	)		—			—		(5,063	)
Other		—			(1,250)			—			—		(1,250)
Advances/investments with affiliates		233,700			(235,607	)		1,907			—		—
Net cash provided by (used in) investing activities		216,276			(68,658	)		(1,157	)		—		146,461
Financing Activities:
Borrowings under credit agreement		40,000			—			—			—		40,000
Repayments under credit agreement		(300,000	)		—			—			—		(300,000	)
Proceeds from issuance of common stock		7,312			—			—			—		7,312
Payment of common stock dividends		(8,547	)		—			—			—		(8,547	)
Net cash used in financing activities		(261,235	)		—			—			—		(261,235	)
Net decrease in cash		(26,511	)		(9,190	)		—			—		(35,701	)
Cash at the beginning of the period		76,763			(32,534	)		—			—		44,229
Cash at end of period	$	50,252		$	(41,724	)	$	—		$	—	$	8,528

26

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the three months ended March 31, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	40,670		$	50,208		$	425		$	—	$	91,303
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment and property acquisitions		(8,833	)		(125,457	)		(876	)		—		(135,166	)
Restricted cash		—			(11,079	)		—			—		(11,079	)
Investment in equity investments		—			(44,500	)		—			—		(44,500	)
Proceeds from disposition of property and equipment		22			66,903			—			—		66,925
Advances/investments with affiliates		(69,984	)		69,533			451			—		—
Net cash used in investing activities		(78,795	)		(44,600	)		(425	)		—		(123,820	)
Financing Activities:
Borrowings under credit agreements		14,979			24,981			—			—		39,960
Repayments under credit agreements		—			(24,981	)		—			—		(24,981	)
Proceeds from issuance of common stock		4,206			—			—			—		4,206
Payment of common stock dividends		(6,364	)		—			—			—		(6,364	)
Settlements of derivative financial instruments with a financing element		(907	)		—			—			—		(907	)
Net cash provided by financing activities		11,914			—			—			—		11,914
Net increase (decrease) in cash		(26,211	)		5,608			—			—		(20,603	)
Cash at the beginning of the period		47,412			20,995			—			—		68,407
Cash at end of period	$	21,201		$	26,603		$	—		$	—	$	47,804

27

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 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, including, but not limited to:

• fluctuations in prices of oil and natural gas;

• imports of foreign oil and natural gas, including liquefied natural gas;

• future capital requirements and availability of financing;

• continued 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 and gathering systems;

• 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;

• risks associated with the proposal by Mr. Miller to acquire our common stock;

• fluctuations in interest rates; and

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

28

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 risk factors and other cautionary statements in this quarterly report, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2010, as amended.

Our revenues, operating results and financial condition depend substantially on prevailing prices for oil and natural gas and the availability of capital from our 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 ability to fund our operations. Lower oil and natural gas prices may also reduce the amount of oil and natural gas we can produce economically. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Overview

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 primary 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. Future acquisitions remain targeted on supplementing our shale resource holdings in the East Texas/North Louisiana and Appalachian areas. 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. In order to accelerate our development efforts, we have entered into four separate joint ventures with affiliates of BG Group, plc, or BG Group. A brief description of each joint venture follows.

• 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 EOC, serving as operator. 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 $400.0 million, or the East Texas/North Louisiana Carry. During the first quarter of 2011, we utilized the remaining balance of the East Texas/North Louisiana Carry.

• A joint venture with BG Group in which we both own a 50% interest in TGGT Holdings, LLC, or TGGT, which holds most of our East Texas/North Louisiana midstream assets.

• A 50/50 joint venture with BG Group covering our shallow producing assets and prospective Marcellus shale acreage in the Appalachia region, or the Appalachia JV. EXCO and BG Group jointly operate the Appalachia JV operations through a 50/50 owned operating entity, or OPCO, which holds a 0.5% working interest in all of the shallow conventional assets and the deep rights in the Appalachia JV. 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, 2011, the remaining balance of the Appalachia Carry was approximately $110.9 million.

• A jointly-owned midstream company, or the Appalachia Midstream JV, to provide take-away capacity in the Marcellus shale.

We expect to continue to grow by leveraging our management and technical team’s experience, appraising and developing our shale resource plays, drilling our multi-year inventory of development locations and accumulating undeveloped acreage in shale areas and implementing exploitation projects. We also continue to pursue acquisitions in the core areas of our shale plays. We employ the use of debt, currently represented by a credit agreement with a borrowing base of $1.5 billion, of which $929.0 million was drawn as of April 28, 2011, or the EXCO Resources Credit Agreement, and $750.0 million of 7.5% senior unsecured notes due September 15, 2018, or the 2018 Notes, along with a comprehensive derivative financial instrument program to mitigate commodity price volatility, to support our strategy.

On October 29, 2010, our Chairman and Chief Executive Officer, Douglas H. Miller presented a letter to our board of directors indicating an interest in acquiring all of the outstanding shares of our stock not already owned by Mr. Miller for a cash purchase price of $20.50 per share. The proposal does not represent a definitive offer and there is no assurance that a definitive offer will be made or accepted, that any agreement will be executed or that any transaction will be consummated.

29

Our board of directors established a special committee on November 4, 2010 comprised of two of our independent directors to, among other things, evaluate and determine the Company’s response to the October 29, 2010 proposal. The special committee retained Kirkland & Ellis LLP and Jones Day as its legal counsel and Barclays Capital, Inc. and Evercore Partners as its financial advisors to assist it in, among other things, evaluating and determining the Company’s response to the proposal. See “Note 16. Acquisition proposal” of the notes to our condensed consolidated financial statements for further information regarding the proposal.

Our plans for 2011 are focused on the Haynesville/Bossier and Marcellus shales. Our budgeted capital expenditures total $976.2 million, of which $864.6 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 $757.0 million. During the first quarter of 2011, we spent $208.1 million in East Texas/North Louisiana, $206.2 million of which was in the area of mutual interest with BG Group, or the East Texas/North Louisiana AMI. In Appalachia, our planned capital expenditures for the Appalachia JV are expected to total $82.8 million, net of $125.0 million of the Appalachia Carry. During the first quarter of 2011, we spent $10.6 million in Appalachia, which reflects the impact of the Appalachia Carry. As of March 31, 2011, the remaining balance of the Appalachia Carry was approximately $110.9 million.

For 2011, TGGT’s capital expenditure budget will focus primarily on well hook-ups in DeSoto Parish and adding infrastructure in the Shelby Area. TGGT’s management is also evaluating several expansion projects. On January 31, 2011, TGGT closed a $500.0 million credit facility, or the TGGT Credit Agreement, and used proceeds from the initial draw to make a capital distribution of $125.0 million to us and BG Group each. We expect the TGGT Credit Agreement, together with its projected cash flows from operations, will be sufficient to fund TGGT’s 2011 capital expenditure programs.

We expect to fund equity contributions to the Appalachia Midstream JV in the future as it builds infrastructure to support our development activities.

For the three months ended March 31, 2011, we produced 36.7 Bcfe of oil and natural gas. Of the amount produced, 32.0 Bcfe were produced in our East Texas/North Louisiana area, 2.8 Bcfe were produced in our Appalachia area and 1.9 Bcfe were produced in our Permian Basin area.

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, 2010, as amended.

Recent events

Haynesville shale acquisition

On April 5, 2011, we closed on a $225.2 million acquisition of land, mineral interests and other assets in DeSoto Parish, Louisiana. BG Group has expressed an interest to participate in this acquisition and acquire its 50% share in accordance with our East Texas/North Louisiana JV.

Amendment of the EXCO Resources Credit Agreement

On April 1, 2011, we entered into the Third Amendment to the EXCO Resources Credit Agreement, resulting in an increase of the borrowing base from $1.0 billion to $1.5 billion. In addition, the interest rate under the EXCO Resources Credit Agreement was reduced by 50 basis points, or bps, and now ranges from LIBOR plus 150 bps to LIBOR plus 250 bps, or from Alternative Base Rate, or ABR, plus 50 bps to ABR plus 150 bps, depending upon borrowing base usage. Our consolidated ratio of funded indebtedness to consolidated EBITDAX (as defined in the agreement) increased by 0.5, so that the ratio can be no greater than 4.0 to 1.0. The maturity date was extended from April 30, 2014 to April 1, 2016.

30

Appalachia Transaction

On March 1, 2011, we jointly closed the purchase of Marcellus shale properties with BG Group, which also included certain shallow production primarily in Jefferson and Clarion counties in Pennsylvania for $81.1 million ($40.5 million net to us), subject to customary post-closing adjustments, or the Appalachia Transaction.

Chief Transaction

On December 21, 2010, we funded the acquisition of undeveloped acreage and oil and natural gas properties primarily in the Marcellus shale from Chief Oil & Gas LLC and related parties for approximately $459.4 million, subject to post-closing title adjustments and customary post-closing purchase price adjustments, or the Chief Transaction. The $459.4 million preliminary purchase price was funded into an escrow account pending receipt of a waiver from a third party, which was received on January 11, 2011 and all properties were released to us. BG Group participated in their 50% share of the Chief Transaction and funded $229.7 million to us on February 7, 2011.

Recent accounting pronouncements

There are no recent accounting pronouncements which we expect would have a significant impact on our financial statements.

Our results of operations

A summary of key financial data for the three months ended March 31, 2011 and 2010 related to our results of operations is presented below:

	Three months ended March 31,					Quarter to quarter  change 2011-2010
(dollars in thousands, except per unit prices)	2011			2010
Production:
Oil (Mbbls)		193			159		34
Natural gas (Mmcf)		35,525			22,837		12,688
Total production (Mmcfe) (1)		36,683			23,791		12,892
Oil and natural gas revenues before derivative financial instrument activities:
Oil	$	17,372		$	11,963	$	5,409
Natural gas		143,856			119,031		24,825
Total oil and natural gas revenues	$	161,228		$	130,994	$	30,234
Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	26,935		$	77,047	$	(50,112	)
Non-cash change in fair value of derivative financial instruments		(23,514	)		22,102		(45,616	)
Total derivative financial instrument activities	$	3,421		$	99,149	$	(95,728	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	90.01		$	75.24	$	14.77
Natural gas (per Mcf)		4.05			5.21		(1.16	)
Natural gas equivalent (per Mcfe)		4.40			5.51		(1.11	)
Costs and expenses:
Oil and natural gas operating costs (2)	$	19,335		$	19,193	$	142
Production and ad valorem taxes		5,599			7,865		(2,266	)
Gathering and transportation		17,286			11,113		6,173
Depletion		63,320			34,020		29,300
Depreciation and amortization		4,610			4,798		(188	)
General and administrative (3)		23,423			26,419		(2,996	)
Interest expense		14,816			10,634		4,182
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.53		$	0.81	$	(0.28	)
Production and ad valorem taxes		0.15			0.33		(0.18	)
Gathering and transportation		0.47			0.47		—
Depletion		1.73			1.43		0.30
Depreciation and amortization		0.13			0.20		(0.07	)
General and administrative		0.64			1.11		(0.47	)
Net income	$	21,941		$	115,568	$	(93,627	)

(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 and $0.4 million for the three months ended March 31, 2011 and 2010, respectively.

(3) Share-based compensation included in general and administrative expenses is $2.6 million and $4.3 million for the three months ended March 31, 2011 and 2010, respectively.

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The following is a discussion of our financial condition and results of operations for the three months ended March 31, 2011 and 2010.

The comparability of our results of operations from period to period is impacted by:

• the Appalachia JV;

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

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

• the equity method of accounting for our investments; and

• significant changes in the amount of 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;

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

• 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 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 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 the natural gas we produce 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 also gather and transport natural gas for other producers for which we are compensated.

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 contained in our properties and related liquidity. 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. Recent economic conditions related to the liquidity and creditworthiness of our purchasers may expose us to risk with respect to the ability to collect payments for the oil and natural gas we deliver.

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Summary

For the three months ended March 31, 2011, we reported net income of $21.9 million compared to net income of $115.6 million for the three months ended March 31, 2010.

The overall decline in net income for three months ended March 31, 2011 from the same period in 2010 is a result of a $6.2 million increase in gathering and transportation expense resulting from new firm transportation contracts and increased production, a $29.1 million increase in depreciation, depletion, and amortization expense resulting from increased production from drilling in the Haynesville area and utilization of the East Texas/North Louisiana Carry, a $4.2 million increase in interest expense due in part to the 2018 Notes and a $95.7 million decrease in gains on derivative financial instruments resulting from the expiration of higher priced derivative financial instruments.

Oil and natural gas production, revenues, and prices

Total equivalent production volumes were 36.7 Bcfe for the three months ended March 31, 2011, a 54.2% increase from the prior year’s comparable period production of 23.8 Bcfe. The increases from the prior year period are primarily a result of increased production in the Haynesville shale, offset by declines in Appalachia due to the formation of the Appalachia JV, which resulted in the sale of 50% of the existing production. The following table reflects elimination of the impact of the Appalachia JV transaction on production to provide a more meaningful analysis of on-going production activity. The pro forma adjustments below reduce our actual production as if the transaction had occurred on January 1, 2010.

	Three months ended March 31,
	2011		2010		2010			2010		Quarter to quarter change
	Actual		Actual		Pro forma			Pro forma		Actual			Pro forma
(in Mmcfe)	production		production		adjustment (1)			production		production			production
Producing region:
East Texas/North Louisiana		31,945		18,753		—			18,753		13,192			13,192
Appalachia		2,780		3,341		(1,622	)		1,719		(561	)		1,061
Permian and other		1,958		1,697		—			1,697		261			261
Total		36,683		23,791		(1,622	)		22,169		12,892			14,514

Production in our East Texas/North Louisiana region for the three months ended March 31, 2011 increased by 13.2 Bcfe from the same period in the prior year. This increase was a result of the continued successful development of our Haynesville shale, which resulted in a production increase of 14.6 Bcfe for the three months ended March 31, 2011 when compared to the same period in the prior year. This increase was offset by production declines of 1.4 Bcfe in our Vernon Field for the three months ended March 31, 2011 when compared to the same period in the prior year. This decline is primarily the result of the suspension of vertical drilling operations and normal production declines. Our Cotton Valley region remained stable, a result of increased production due to workovers, offset by normal production declines. On a pro forma basis, the Appalachia region experienced production increases due primarily to new production in the Marcellus shale, resulting from the commencement of our Marcellus shale horizontal drilling program in 2010 and volumes attributable to the Chief Transaction. Our Permian Basin area and other divisions also experienced a production increase due to resuming drilling operations during 2010.

The following table presents our revenues, production and average sales prices by major producing areas, based on historical data, for the three months ended March 31, 2011 and 2010:

	Three months ended March 31,
	2011						2010						Quarter to quarter change
	Production						Production						Production
(dollars in thousands, except per unit rate)	(Mmcfe)		Revenue		$/Mcfe		(Mmcfe)		Revenue		$/Mcfe		(Mmcfe)			Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana		31,945	$	125,206	$	3.92		18,753	$	93,995	$	5.01		13,192		$	31,211		$	(1.09	)
Appalachia		2,780		12,637		4.55		3,341		19,354		5.79		(561	)		(6,717	)		1.24
Permian and other		1,958		23,385		11.94		1,697		17,645		10.40		261			5,740			1.54
Total		36,683	$	161,228		4.40		23,791	$	130,994		5.51		12,892		$	30,234			(1.11	)

For the three months ended March 31, 2011, oil and natural gas revenues were $161.2 million, a 23.1% increase from the oil and natural gas revenues of $131.0 million for the three months ended March 31, 2010. The increase in revenues is primarily a result of the overall increased production in our Haynesville operations and an increase in oil prices, offset by lower natural gas prices. The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased from $75.24 per Bbl for the three

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months ended March 31, 2010 to $90.01 per Bbl for the three months ended March 31, 2011, or 19.6%. The average natural gas sales price, excluding the impact of derivative financial instruments, was $4.05 per Mcf for the three months ended March 31, 2011 compared with $5.21 per Mcf for the three months ended March 31, 2010, a decrease of 22.3%.

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. 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, 2011 average production levels for the remainder of the year, a change of $0.10 per Mcf of natural gas sold would result in an increase or decrease in revenues of approximately $10.7 million and a change 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 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.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three months ended March 31, 2011 were $19.3 million, a slight increase from the $19.2 million we incurred in oil and natural gas operating costs for the three months ended March 31, 2010. The primary reason for the slight increase was due to the continued activity in the Haynesville shale area and workover activity in our Vernon Field and our Cotton Valley Wells, offset by the declines in Appalachia related to the Appalachia JV. To further analyze the variances in costs, management reviews the costs on a per Mcfe basis, as they believe this measure excludes the impact of any acquisitions or divestitures, such as the Appalachia JV.

As shown in the table below, on a per Mcfe basis, oil and natural gas operating expenses for the three months ended March 31, 2011 decreased $0.28, or 34.6%, per Mcfe from the same period in 2010, with lease operating expenses representing the entire $0.28 per Mcfe of the decrease and there being no change in total workovers and other expense per Mcfe. The net decrease in oil and natural gas operating expenses per Mcfe in East Texas/North Louisiana is a result of increased production in our Haynesville shale, which has a relatively low lease operating rate per Mcfe, and is partially offset by costs in our Vernon Field and Cotton Valley area, which have higher lease operating expense rates per Mcfe. Decreases in Appalachia are primarily a result of increased production in the Marcellus shale, which has a lower lease operating expense rate per Mcfe than our historical shallow production.

	Three months ended March 31,
	2011						2010						Quarter to quarter change
	Lease						Lease						Lease
	operating		Workovers				operating		Workovers				operating			Workovers
(in thousands)	expenses		and other		Total		expenses		and other		Total		expenses			and other			Total
Producing region:
East Texas/North Louisiana	$	11,292	$	2,516	$	13,808	$	10,529	$	1,390	$	11,919	$	763		$	1,126		$	1,889
Appalachia		2,916		—		2,916		4,787		136		4,923		(1,871	)		(136	)		(2,007	)
Permian and other		2,528		83		2,611		2,134		217		2,351		394			(134	)		260
Total	$	16,736	$	2,599	$	19,335	$	17,450	$	1,743	$	19,193	$	(714	)	$	856		$	142
	Three months ended March 31,
	2011						2010						Quarter to quarter change
	Lease						Lease						Lease
	operating		Workovers				operating		Workovers				operating			Workovers
(per Mcfe)	expenses		and other		Total		expenses		and other		Total		expenses			and other			Total
Producing region:
East Texas/North Louisiana	$	0.35	$	0.08	$	0.43	$	0.56	$	0.07	$	0.63	$	(0.21	)	$	0.01		$	(0.20	)
Appalachia		1.05		—		1.05		1.43		0.04		1.47		(0.38	)		(0.04	)		(0.42	)
Permian and other		1.29		0.04		1.33		1.26		0.13		1.39		0.03			(0.09	)		(0.06	)
Total	$	0.46	$	0.07	$	0.53	$	0.74	$	0.07	$	0.81	$	(0.28	)	$	(0.00	)	$	(0.28	)

Midstream operations

We own a 50% membership interest in two midstream joint ventures, TGGT and Appalachia Midstream JV. The joint venture activities relate to sales of natural gas purchased for resale and fees earned from gathering, treating and compression of natural gas. Our joint ventures do not own any natural gas processing facilities.

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TGGT holds our East Texas/North Louisiana midstream assets, exclusive of the Vernon Field gathering assets. TGGT is accounted for using the equity method of accounting. Effective with the formation of TGGT in August 2009, the net operations from our gathering assets located in our Vernon Field, which were not contributed to TGGT, are reflected as a component of “Gathering and transportation” on our consolidated statements of operations.

Due to the rapid natural gas production growth in the Haynesville/Bossier shale, TGGT has increased its throughput dramatically in its core areas of operation within East Texas and North Louisiana. TGGT’s primary customers are EXCO and BG Group. TGGT 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. Total throughput for TGGT averaged approximately 1.2 Bcf per day for the first quarter of 2011.

TGG operates amine, glycol, and H₂S treating facilities, which treat natural gas in order to meet pipeline quality specifications for downstream transportation. TGGT’s system has access to 14 interstate and intrastate pipeline markets. TGG has approximately 126 miles of pipeline comprised of 12, 16, and 20-inch diameter pipe in its legacy East Texas area. TGG continues to see growth in throughput from the Haynesville and Bossier shales in its shale-focused system in the North Louisiana area where TGG has approximately 27 miles of pipeline comprised of 36-inch diameter pipe.

Additionally, TGG has initiated major midstream expansion efforts in the Shelby Area in East Texas. TGG is installing the gathering pipelines and treating facilities necessary to meet the throughput volume increase expected from this area. The throughput capacity is planned to increase to approximately 740 Mmcf per day by the third quarter of 2011 and treating capacity in excess of 500 Mmcf per day by year end 2011.

The Appalachia Midstream JV is evaluating alternatives for system development, which will be built to support our development drilling program in the Appalachia JV.

Gathering and transportation

We report gathering and transportation costs in accordance with Accounting Standards Codification 605-45, or ASC 605-45. 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 contain revenues which are reported under two separate bases. Gathering and transportation expenses totaled $17.3 million for the three months ended March 31, 2011 compared to $11.1 million for the three months ended March 31, 2010. The overall increase in gathering and transportation expenses is a result of increased volumes, new firm transportation agreements in the Haynesville area, which commenced in February 2010, along with the fees charged by TGGT.

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. By the end of 2011, our firm transportation agreements will cover over 860 Bcf per day with annual minimum gathering expenses of approximately $90.0 million.

Production and ad valorem taxes

Production and ad valorem taxes for the three months ended March 31, 2011 decreased by $2.3 million, or 28.8%, over the same period in 2010. On a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 3.5% of gross oil and natural gas sales for the three months ended March 31, 2011 compared with 6.0% during the same period in the prior year.

The decrease in the percentage of revenue basis for the three months ended March 31, 2011 compared to the same period in 2010 is primarily the result of the receipt of severance tax holidays on our Haynesville and Bossier shale wells in Louisiana, along with a decrease in the severance tax rate, as discussed below. 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, production taxes are predominantly price dependent.

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In addition to our existing production and ad valorem taxes on current properties, we may be subject to new taxes or changes to existing rates in the future. The State of Louisiana, which has a history of adjusting its severance tax rate each July, decreased its severance tax rate from $0.33 to $0.164 per Mcf effective July 1, 2010. In addition, the Commonwealth of Pennsylvania is contemplating an impact fee in lieu of a severance tax. Legislation that describes the impact fee is expected to be introduced in the Pennsylvania Senate in April 2011. Whether this legislation will be approved by the Pennsylvania House and ultimately the Governor of Pennsylvania is unknown at this time.

Overall, our severance and ad valorem tax rates were $0.15 per Mcfe for the three months ended March 31, 2011 compared with $0.33 per Mcfe for the three months ended March 31, 2010. The following tables present 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,
	2011											2010
(dollars in thousands, except per unit rate)	Revenue		Production (Mmcfe)		Severance and ad valorem taxes		Taxes % of revenue			Taxes $/Mcfe		Revenue		Production (Mmcfe)		Severance and ad valorem taxes		Taxes % of revenue			Taxes $/Mcfe
Producing region:
East Texas/North Louisiana	$	125,206		31,945	$	3,634		2.9	%	$	0.11	$	93,995		18,753	$	5,498		5.8	%	$	0.29
Appalachia		12,637		2,780		289		2.3	%		0.10		19,354		3,341		766		4.0	%		0.23
Permian and other		23,385		1,958		1,676		7.2	%		0.86		17,645		1,697		1,601		9.1	%		0.94
Total	$	161,228		36,683	$	5,599		3.5	%		0.15	$	130,994		23,791	$	7,865		6.0	%		0.33

Depletion

Our depletion expense for the three months ended March 31, 2011 increased by $29.3 million, or 86.1% from the same periods in 2010. The increase was a result of increased drilling on proved undeveloped locations in the Haynesville area and utilization of the East Texas/North Louisiana Carry. We expect the depletion rate to continue to increase during 2011 as the Appalachia Carry is utilized. On a per Mcfe basis, our depletion rate for the three months ended March 31, 2011 was $1.73 compared with $1.43 for the prior year period.

Depreciation and amortization

Our depreciation and amortization costs for the three months ended March 31, 2011 decreased by $0.2 million, or 3.9% from the same period in 2010.

Accretion of discount on asset retirement obligations for the three months ended March 31, 2011 decreased by $0.2 million, or 21.3% from the same period in 2010. The decrease was due to the Appalachia JV, offset by significant well additions and related future plugging liabilities in connection with our 2010 and first quarter 2011 well additions.

General and administrative

The following table presents our general and administrative expenses for the three months ended March 31, 2011 and 2010:

	Three months ended March  31,						Quarter to quarter change
(in thousands, except per unit rate)	2011			2010
General and administrative costs:
Gross general and administrative expense	$	31,848		$	33,153		$	(1,305	)
Operator overhead reimbursements		(4,318	)		(3,770	)		(548	)
Capitalized acquisition and development charges		(4,107	)		(2,964	)		(1,143	)
General and administrative expense	$	23,423		$	26,419		$	(2,996	)
General and administrative expense per Mcfe	$	0.64		$	1.11		$	(0.47	)

Our general and administrative costs for the three months ended March 31, 2011 were $23.4 million, or $0.64 per Mcfe, compared to $26.4 million, or $1.11 per Mcfe, for the same period in 2010, a decrease of $3.0 million, or 11.3%.

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Significant components of the net decrease for the three months ended March 31, 2011 include the following items:

• decreased legal costs of $2.0 million for the three months ended March 31, 2011 due to a decrease in various claims and settlements;

• decreased share-based compensation costs of $1.7 million for the three months ended March 31, 2011 due primarily to a reduction in options granted in 2010 compared to prior years;

• decreased building rent and associated fees of $0.3 million for the three months ended March 31, 2011 due primarily to the closure of our Ohio offices;

• increased capitalized charges of $1.1 million for the three months ended March 31, 2011, primarily related to increased personnel;

• increased operator overhead recoveries of $0.5 million for the three months ended March 31, 2011 due to increased drilling in our shale plays; and

• increased recoveries of technical and administrative service costs of $1.1 million from our service agreement with BG Group for the three months ended March 31, 2011.

The above decreases are partially offset by personnel charges of $2.8 million for the three months ended March 31, 2011 due primarily to technical employees hired to exploit our shale resource asset base and a $0.7 million increase associated with third party contractor costs.

Interest expense

Our interest expense increased approximately $4.2 million for the three months ended March 31, 2011 from the same periods in 2010. The quarter increases were primarily due to the 2018 notes, which were issued in September 2010, interest costs on the EXCO Resources Credit Agreement, which was a result of the consolidation of the EXCO Operating Credit Agreement into the EXCO Resources Credit Agreement in April 2010, and $1.2 million of costs we agreed to pay in connection with the closing of the TGGT Credit Agreement. These increases were offset by the redemption of our 2011 Notes in September 2010, the EXCO Operating Credit Agreement consolidating into the EXCO Resources Credit Agreement, and capitalizing more interest as we continue to acquire acreage.

	Three months ended March 31,						Quarter to quarter change
(in thousands)	2011			2010
Interest expense:
2011 Notes (1)	$	—		$	7,127		$	(7,127	)
2018 Notes		14,320			—			14,320
EXCO Resources Credit Agreement		5,193			864			4,329
EXCO Operating Credit Agreement (2)		—			4,567			(4,567	)
Amortization and write-off of deferred financing costs on EXCO Resources Credit Agreement		1,223			351			872
Amortization of deferred financing costs on EXCO Operating Credit Agreement (2)		—			493			(493	)
Amortization of deferred financing costs on 2018 Notes		467			—			467
Interest rate swaps settlements		—			2,063			(2,063	)
Fair market value adjustment on interest rate swaps		—			(2,018	)		2,018
Capitalized interest		(7,740	)		(2,915	)		(4,825	)
Other		1,353			102			1,251
Total interest expense	$	14,816		$	10,634		$	4,182

(1) The 2011 Notes were redeemed in October 2010.

(2) The EXCO Operating Credit Agreement was consolidated with the EXCO Resources Credit Agreement on April 30, 2010.

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 oil and natural gas 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

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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 consolidated statements of operations.

		$(95,728)			$(95,728)		$(95,728)
	Three months ended March 31,					Quarter to quarter  change
(in thousands)	2011			2010
Derivative financial instrument activities:
Cash settlements on derivative financial instruments, excluding early terminations	$	26,935		$	39,111	$	(12,176	)
Cash settlements on early terminations of derivative financial instruments		—			37,936		(37,936	)
Non-cash change in fair value of derivative financial instruments		(23,514	)		22,102		(45,616	)
Total derivative financial instrument activities	$	3,421		$	99,149	$	(95,728	)

The use of derivative financial instruments allows us to limit the impacts of volatile oil and natural gas price fluctuations. The following table presents our natural gas prices, before the impact of derivative financial instruments. Average realized prices per Mcfe decreased from $5.51 during the three months ended March 31, 2010 to $4.40 during the three months ended March 31, 2011. Cash settlements on our derivative financial instruments, excluding early terminations, increased our average realized price from $4.40 Mcfe to $5.13 per Mcfe for the three months ended March 31, 2011 and from $5.51 per Mcfe to $7.15 per Mcfe for the three months ended March 31, 2010.

		$(95,728)		$(95,728)		$(95,728)
	Three months ended March 31,				Quarter to quarter  change
Realized pricing:	2011		2010
Oil per Bbl	$	90.01	$	75.24	$	14.77
Natural gas per Mcf		4.05		5.21		(1.16	)
Natural gas equivalent per Mcfe	$	4.40	$	5.51	$	(1.11	)
Cash settlements on derivatives, excluding early terminations, per Mcfe		0.73		1.64		(0.91	)
Net price per Mcfe, including derivative financial instruments before early terminations	$	5.13	$	7.15	$	(2.02	)
Cash settlements on early terminations of derivative financial instruments, per Mcfe		—		1.60		(1.60	)
Net price per Mcfe, derivative financial instruments	$	5.13	$	8.75	$	(3.62	)

Our total cash settlements for the three months ended March 31, 2011 increased revenue by $26.9 million, or $0.73 per Mcfe, compared to $77.1 million, or $3.24 per Mcfe, for the same period in 2010. As noted above, the significant fluctuations between settlements of receipts on our derivative financial instruments demonstrate the aforementioned 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, 2011 resulted in losses of $23.5 million compared to gains of $22.1 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 years. 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 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.

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Income taxes

Our effective income tax rate for the three months ended March 31, 2011 and 2010 was zero due to current operating losses arising from ceiling test write-downs in 2008 and 2009 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, 2011 is approximately $380.0 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, 2011 and 2010 would have been approximately 40.0%.

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 and capital markets when market conditions are favorable. Prior to our increased emphasis on horizontal drilling in our shale resource plays, we targeted funding our drilling and development capital spending programs within cash flows from operations. However, our capital expenditure requirements to develop the Haynesville/Bossier shale prospects, our Marcellus shale acreage and the related midstream infrastructures are significant. While we expect our shale development programs to contribute significant reserve additions and production volumes, the required development capital to achieve these results are expected to exceed internally generated cash flow in 2011 and 2012. However, we believe reserve additions and related borrowing base increases will be sufficient to execute our development plans. Continued volatility in natural gas prices may impact our development plans.

Other factors which may impact our liquidity, capital resources and capital commitments in 2011 include the following:

• the results of our appraisal and exploration programs in the Marcellus shale;

• a continuation of low natural gas prices;

• decisions by BG Group not to participate for their 50% share in acquisitions intended for either the East Texas/North Louisiana JV or the Appalachia JV;

• time lags in receiving reimbursements from BG Group related to purchases for their 50% share in property acquisitions in which they elect to participate;

• continued expansion of our technical personnel required to support our drilling programs, particularly in Appalachia;

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

• acquisitions of unproved or undeveloped oil and natural gas properties which produce little or no current cash flows; and

• upward trends in service costs related to horizontal drilling and completions.

Each of the aforementioned factors could impact our near-term liquidity and we expect that we will be required to draw on our EXCO Resources Credit Agreement or seek other sources of capital to fund our operations. Acquisitions are generally not budgeted as they tend to be opportunity driven and our current strategy is to limit acquisition activity to our target areas (East Texas/North Louisiana and Appalachia) for contiguous acreage blocks or “bolt-on” acreage, as economic conditions permit.

Our capital budget for 2011 totals $976.2 million and reflects our focus on the development of our Haynesville and Bossier shale plays in East Texas/North Louisiana and an increased emphasis in the Marcellus shale in Appalachia. The East Texas/North Louisiana JV in 2009 and the Appalachia JV in 2010 each reduced our ownership interests in these properties by approximately 50%. Each of the joint ventures provided for BG Group to fund 75% of our share of drilling and development costs on horizontal wells, up to specified dollar limits of $400.0 million in East Texas/North Louisiana and $150.0 million in Appalachia. During the first quarter of 2011, we utilized the remaining balance of the East Texas/North Louisiana Carry. As of April 28, 2011, approximately $109.1 million of the Appalachia Carry remained unused.

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The following table presents capital expenditures for the first quarter of 2011 and the capital budget for the remainder of 2011, exclusive of acquisitions, which are not budgeted. The remaining budget for 2011 does not include amounts attributable to our interests that will be paid by BG Group pursuant to the Appalachia Carry.

	Three months ended March 31,		April - December Forecast		Full Year Forecast
(in thousands)	2011		2011		2011
Capital expenditures:
Development capital expenditures	$	198,288	$	632,416	$	830,704
Lease purchases(1)		24,546		33,954		58,500
Seismic		4,447		6,953		11,400
Gas gathering and water pipelines		812		16,588		17,400
Corporate and other		17,518		40,682		58,200
Total capital expenditures	$	245,611	$	730,593	$	976,204

(1) Net of acreage reimbursements from BG Group totaling $22.9 million ($5.5 million received in Q1 2011 and expected future reimbursements of $17.4 million).

Recent events affecting liquidity

On December 21, 2010, we funded the acquisition of undeveloped acreage and oil and natural gas properties primarily in the Marcellus shale from Chief Oil & Gas LLC and related parties for approximately $459.4 million, subject to customary post-closing purchase price adjustments and post-closing title adjustments. The $459.4 million preliminary purchase price was funded into an escrow account pending receipt of a waiver from a third party, which was received on January 11, 2011 and all properties were released to us. BG Group participated in its 50% share of the Chief Transaction and funded $229.7 million to us on February 7, 2011.

On January 31, 2011, TGGT closed the TGGT Credit Agreement and used proceeds from the initial draw to make a return of capital distribution to us and BG Group of $125.0 million each. We used this distribution to reduce the borrowings under the EXCO Resources Credit Agreement. The TGGT Credit Agreement, of which an affiliate of BG Group is a co-lender, matures on January 31, 2016 and is collateralized by first lien mortgages on substantially all of the real and personal property of TGGT, including all of the equity interests of TGGT’s subsidiaries. The equity interests of TGGT held by us and BG Group are not pledged and neither we nor BG Group provide any guarantees or other credit support to the lenders. We expect the TGGT Credit Agreement, together with its projected cash flows from operations, will be sufficient to fund TGGT’s 2011 capital expenditure programs, which should substantially eliminate our obligation to provide direct funding for TGGT capital programs and provide us with additional liquidity to fund our upstream operations.

On March 1, 2011, we jointly closed the purchase of additional Marcellus shale properties with BG Group, which also included certain shallow production primarily in Jefferson and Clarion counties in Pennsylvania for $81.1 million ($40.5 million net to us), subject to customary post-closing adjustments.

On April 1, 2011, we entered into the Third Amendment to the EXCO Resources Credit Agreement, resulting in an increase of the borrowing base from $1.0 billion to $1.5 billion. In addition, the interest rate under the EXCO Resources Credit Agreement was reduced by 50 bps and now ranges from LIBOR plus 150 bps to LIBOR plus 250 bps, or from ABR plus 50 bps to ABR plus 150 bps, depending upon borrowing base usage. Our consolidated ratio of funded indebtedness to consolidated EBITDAX (as defined in the agreement) increased by 0.5, so that the ratio can be no greater than 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2010. The maturity date was extended from April 30, 2014 to April 1, 2016.

On April 5, 2011, we closed on a $225.2 million acquisition of land, mineral interests and other assets in DeSoto Parish, Louisiana. BG Group has expressed an interest to participate in this acquisition and acquire its 50% share in accordance with the East Texas/North Louisiana JV.

Although recent financial reform legislation may negatively affect the capital and credit markets, and the weakness in certain commodity prices has continued, particularly for natural gas, we believe that our capital resources from existing cash balances, anticipated cash flow from operating activities and available increased borrowing capacity under the EXCO Resources Credit Agreement will be adequate to execute our corporate strategies and to meet debt service obligations. Our future cash flows from operations are subject to a number of variables, including production volumes, oil and natural gas prices and drilling and service costs. The effectiveness of our derivative financial instruments and our ability to enter into additional derivative financial instruments may also impact our future cash flows. While we continue to evaluate opportunities to enter into derivative financial instruments, our recent percentage of expected production covered by derivative financial instruments has decreased compared to previous years.

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The following table presents our liquidity and borrowing availability as of March 31, 2011 and April 28, 2011.

(in thousands)	March 31, 2011		April 28, 2011
Cash (1)	$	159,120	$	274,904
Drawings under the EXCO Resources Credit Agreement		589,000		929,000
2018 Notes (2)		750,000		750,000
Total debt		1,339,000		1,679,000
Net debt	$	1,179,880	$	1,404,096
Consolidated borrowing base	$	1,000,000	$	1,500,000
Total of unused borrowing base (3)	$	395,498	$	555,498
Unused borrowing base plus cash (1) (3)	$	554,618	$	830,402

(1) Includes restricted cash of $150.6 million at March 31, 2011 and $169.7 million at April 28, 2011.

(2) Excludes unamortized bond discount of $10.5 million at March 31, 2011 and $10.4 million at April 28, 2011.

(3) Net of $15.5 million in letters of credit at March 31, 2011 and April 28, 2011.

Historical sources and uses of funds

The following table reflects net increases and decreases in cash for the three months ended March 31, 2011 and 2010.

	Three months ended March 31,
(amounts in thousands)	2011			2010
Cash flows provided by operating activities	$	79,073		$	91,303
Cash flows provided by (used in) investing activities		146,461			(123,820	)
Cash flows provided by (used in) financing activities		(261,235	)		11,914
Net decrease in cash	$	(35,701	)	$	(20,603	)

Our primary sources of cash in the first quarter of 2011 were from cash flow from operations, amounts received from BG Group to reimburse us for its 50% share of the Chief Acquisition of $229.7 million and receipt of $125.0 million in return of capital distributions from TGGT.

Cash flows from operations

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 and, (iv) costs of our general and administrative activities. Net cash provided by operations for the three months ended March 31, 2011 was $79.1 million compared with $91.3 million for the three months ended March 31, 2010. The 12.4% decrease in the current year quarter is due primarily to a reduction in the cash settlements on our derivatives offset by an increase in our production and sales. As of April 28, 2011, our cash and cash equivalent balance was $105.2 million and our restricted cash account, which is principally used for Haynesville/Bossier shale development operations, was $169.7 million.

Investing activities and transactions

Our investing activities consist primarily of drilling and development expenditures, capital contributions to our joint ventures, and acquisitions, including prospective acreage acquisitions in our target areas. 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. We also receive reimbursements from BG Group on these acquisitions as it elects to participate. 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.

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In the quarter ended March 31, 2011, our cash flows from investing activities were favorably impacted by the receipt of a $125.0 million return of capital distribution from TGGT and receipt of $229.7 million from BG Group for its 50% share of the Chief Transaction. These inflows were offset by ongoing drilling and development expenditures and the Appalachia Transaction.

Cash flows from financing activities

During the three months ended March 31, 2011, we repaid borrowings under the EXCO Resources Credit Agreement with $229.7 million received from BG Group to reimburse us for its share of the Chief Acquisition and $125.0 million return of capital distributions from TGGT.

EXCO Resources Credit Agreement and long-term debt

As of April 28, 2011, we had total debt outstanding of approximately $1.7 billion, consisting of borrowings under the EXCO Resources Credit Agreement of $929.0 million and $750.0 million of the 2018 Notes. Terms and conditions of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

At March 31, 2011, the EXCO Resources Credit Agreement had a borrowing base of $1.0 billion and outstanding indebtedness of $589.0 million. On April 1, 2011, following completion of the regular semi-annual redetermination of our borrowing base, we entered into the Third Amendment to the EXCO Resources Credit Agreement with the lenders in the bank syndicate. The Third Amendment to the EXCO Resources Credit Agreement provided the following changes:

• increased our borrowing base under the EXCO Resources Credit Agreement to $1.5 billion from $1.0 billion;

• decreased the interest rate by 50 bps such that the rates now range from LIBOR plus 150 bps to LIBOR plus 250 bps or from ABR plus 50 bps to ABR plus 150 bps, depending on borrowing base usage;

• increased the maximum ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the agreement) to 4.0 to 1.0 from 3.5 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2010; and

• extended the maturity of the agreement to April 1, 2016 from April 30, 2014.

The majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement. The EXCO Resources Credit Agreement permits certain investments, loans and advances to the unrestricted subsidiaries related to our joint ventures. 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 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.

As of March 31, 2011, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, as amended, which require 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 to consolidated EBITDAX (as defined in the agreement) to be greater than 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2010.

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

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2018 Notes

On September 15, 2010 we closed on an underwritten offering of $750.0 million of the 2018 Notes and concurrently provided notice to the trustee for our 2011 Notes in accordance with the indenture to fully redeem all of the $444.7 million in outstanding notes on October 15, 2010. We used a portion of the proceeds from the issuance of the 2018 Notes for the redemption of the 2011 Notes, including accrued interest of $8.1 million from July 15, 2010 to the redemption date. 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, 2011, $750.0 million in principal was outstanding on our 2018 Notes. The unamortized discount on the 2018 Notes at March 31, 2011 was $10.5 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $762.2 million on March 31, 2011.

Interest on the 2018 Notes 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.

Other activities

On July 19, 2010, we announced a stock repurchase program whereby we are permitted, but not required, to repurchase up to $200.0 million of our common stock in open market transactions, in privately negotiated transactions or through a structured share repurchase program. Funds for the share repurchases will be from available cash or borrowings under our existing debt facilities. As of April 28, 2011, we have purchased 539,221 shares of our common stock at an aggregate cost of $7.5 million. The program was suspended as a result of the pending strategic alternatives being evaluated by a special committee of our Board of Directors in connection with the October 29, 2010 proposal from our Chairman and Chief Executive Officer to purchase all of the outstanding shares of common stock that he does not already own.

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.

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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, 2011, 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 2011		22,295	$	5.28		137	$	111.32
Q3 2011		22,540		5.28		138		111.32
Q4 2011		22,540		5.28		138		111.32
2012		53,070		5.37		275		95.70
2013		5,475		5.99		—		—

Off-balance sheet arrangements

We have 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)		—		—		—		589,000		589,000
Firm transportation services(3)		74,585		185,114		182,743		452,429		894,871
Other fixed commitments(4)		119,845		142,188		22,180		7,130		291,343
Drilling contracts		80,835		44,807		381		—		126,023
Operating leases		7,047		13,141		9,077		840		30,105
Total contractual obligations	$	282,312	$	385,250	$	214,381	$	1,799,399	$	2,681,342

(1) Our 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.

(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.

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.

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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, 2011.

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at March 31, 2011
Natural gas:
Swaps:
Remainder of 2011		67,375	$	5.28	$	47,452
2012		53,070		5.37		16,294
2013		5,475		5.99		3,124
Total natural gas		125,920				66,870
Oil:
Swaps:
Remainder of 2011		413		111.32		1,396
2012		275		95.70		(2,856	)
Total oil		688				(1,460	)
Total oil and natural gas derivatives					$	65,410

At March 31, 2011, the average forward NYMEX oil prices per Bbl for the remainder of 2011 and for 2012 were $107.50 and $106.29, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2011 and for 2012 were $4.61 and $5.06, 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, 2011, for the remainder of 2011, if the settlement price exceeds the actual weighted average strike price of $111.32 per Bbl, then a reduction in other income would be recorded for the difference between the settlement price and $111.32 per Bbl, multiplied by the hedged volume of 413 Mbbls. Conversely, if the settlement price is less than $111.32 per Bbl, then an increase in other income would be recorded for the difference between the settlement price and $111.32 per Bbl, multiplied by the hedged volume of 413 Mbbls. For example, for a hedged volume of 413 Mbbls, if the settlement price is $112.32 per Bbl then other income would decrease by $0.4 million. Conversely, if the settlement price is $110.32 per Bbl, other income would increase by $0.4 million.

Interest rate risk

At March 31, 2011, 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, 2011, we had approximately $589.0 million in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% change in interest rates based on the variable borrowings as of March 31, 2011 would result in an increase or decrease in our interest costs of $5.9 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

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Item 4. Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that EXCO’s disclosure controls and procedures were effective as of March 31, 2011 to ensure that information that is required to be disclosed by EXCO in the reports it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to EXCO’s management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There were no changes in EXCO’s internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, EXCO’s internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of business, we are periodically a party to lawsuits and claims. 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. See “Note 16. Acquisition proposal” of the notes to our consolidated financial statements for information regarding certain lawsuits against the Company or members of the board of directors in connection with Mr. Miller’s acquisition proposal.

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, 2011:

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, 2011		0	$	0.00		0	$	192.5 million
February 1 - February 28, 2011		0	$	0.00		0	$	192.5 million
March 1 - March 31, 2011		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. The program was suspended as a result of the pending strategic alternatives being evaluated by a special committee of our Board of Directors in connection with the October 29, 2010 proposal from our Chairman and Chief Executive Officer to purchase all of our outstanding common stock that he does not already own.

Item 6. Exhibits

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

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SIGNATURES

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

EXCO RESOURCES, INC.
(Registrant)
Date: May 4, 2011	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

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INDEX TO EXHIBITS

Exhibit Number	Description of Exhibits
2.1	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Operating Company, LP, as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.2	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Resources, Inc., as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.3	Purchase and Sale Agreement, dated June 29, 2009, by and among EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.4	Contribution Agreement, dated August 5, 2009, by and among Vaughan Holding Company, LLC, EXCO Operating Company, LP and BG US Gathering Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
2.5	First Amendment, dated July 13, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.6	Second Amendment, dated August 5, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11 , 2009 and incorporated by reference herein.
2.7	Purchase and Sale Agreement, dated September 29, 2009, by and between EXCO—North Coast Energy, Inc., Inc., as seller, and EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., and EV Properties, L.P., as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
2.8	Purchase and Sale Agreement, dated September 30, 2009, by and between EXCO Resources, Inc., as seller, and Sheridan Holding Company I, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
2.9	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.
2.10	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 herein by reference.
2.11	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 herein by reference.
2.12	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 herein by reference.
2.13	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 herein by reference.
2.14	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 herein by reference.
2.15	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 herewith as Exhibit 10.35.

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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, 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, 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 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 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 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 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 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 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.
4.5	Rights Agreement, dated as of January 12, 2011, by and between EXCO Resources, Inc. and Continental Stock Transfer & Trust Company, as Rights Agent, 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.

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10.1	Underwriting Agreement, dated September 10, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries, and J.P. Morgan Securities LLC, on behalf of itself and the other underwriters listed on Schedule 1 thereto, 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.
10.2	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.*
10.3	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.*
10.4	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.*
10.5	Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.*
10.6	Fourth Amended and Restated EXCO Resources, Inc. Severance Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 16, 2011 and filed on March 22, 2011 and incorporated by reference herein.*
10.7	Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.
10.8	Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated herein by reference.
10.9	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 dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
10.10	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 dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
10.11	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Operating Company, LP, as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.12	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Resources, Inc., as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.13	Purchase and Sale Agreement, dated June 29, 2009, by and among EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.14	Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.
10.15	Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LP and EXCO Production Company, LP, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.
10.16	Amendment to Joint Development Agreement, dated February 1, 2011, by and among BG US Production Company, LLC and EXCO Operating Company, LP, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated herein by reference.
10.17	Contribution Agreement, dated August 5, 2009, by and among Vaughan Holding Company, LLC, EXCO Operating Company, LP and BG US Gathering Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.

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10.18	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.
10.19	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 herein by reference.
10.20	First Amendment, dated July 13, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.21	Second Amendment, dated August 5, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
10.22	Purchase and Sale Agreement, dated September 29, 2009, by and between EXCO - North Coast Energy, Inc., Inc., as seller, and EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., and EV Properties, L.P., as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
10.23	Purchase and Sale Agreement, dated September 30, 2009, by and between EXCO Resources, Inc., as seller, and Sheridan Holding Company I, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
10.24	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.
10.25	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 herein by reference.
10.26	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.
10.27	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.
10.28	Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.29	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.
10.30	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 herein by reference.
10.31	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 herein by reference.

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10.32	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 herein by reference.
10.33	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 herein by reference.
10.34	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 herein by reference.
10.35	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 herewith.
10.36	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.
10.37	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.
10.38	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.
10.39	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.
10.40	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.
10.41	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.
10.42	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.
10.43	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.
10.44	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.

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10.45	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 herein by reference.
10.46	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 herein by reference.
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.

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