Exco Resources (EXCO) 10-Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 July 27, 2011 was 214,051,219.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010	3
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010	5
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010	6
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Six Months Ended June 30, 2011 and 2010	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	53
PART II.	OTHER INFORMATION	55
Item 1.	Legal Proceedings	55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 5.	Other Information	55
Item 6.	Exhibits	55
	Signatures	56

2

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	June 30, 2011			December 31, 2010
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	65,186		$	44,229
Restricted cash		149,215			161,717
Accounts receivable, net:
Oil and natural gas		123,302			80,740
Joint interest		105,194			104,358
Interest and other		25,973			35,594
Inventory		8,196			7,876
Derivative financial instruments		69,187			73,176
Other		17,872			12,770
Total current assets		564,125			520,460
Equity investments		273,632			379,001
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		783,621			599,409
Proved developed and undeveloped oil and natural gas properties		3,038,647			2,370,962
Accumulated depletion		(1,456,225	)		(1,312,216	)
Oil and natural gas properties, net		2,366,043			1,658,155
Gas gathering assets		160,111			157,929
Accumulated depreciation and amortization		(29,114	)		(24,772	)
Gas gathering assets, net		130,997			133,157
Office, field, and other equipment, net		43,582			43,149
Deferred financing costs, net		33,822			30,704
Derivative financial instruments		21,992			23,722
Goodwill		218,256			218,256
Deposits on acquisitions		0			464,151
Other assets		6,665			6,665
Total assets	$	3,659,114		$	3,477,420

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share and share data)	June 30, 2011			December 31, 2010
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	157,117		$	152,999
Revenues and royalties payable		178,151			108,830
Accrued interest payable		17,943			18,983
Current portion of asset retirement obligations		1,279			900
Income taxes payable		0			211
Derivative financial instruments		2,552			3,775
Total current liabilities		357,042			285,698
Long-term debt		1,591,288			1,588,269
Deferred income taxes		0			0
Derivative financial instruments		3,162			4,200
Asset retirement obligations and other long-term liabilities		60,889			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; 214,557,830 shares issued and 214,018,609 shares outstanding at June 30, 2011; 213,736,266 shares issued and 213,197,045 shares outstanding at December 31, 2010		215			214
Additional paid-in capital		3,170,496			3,151,513
Accumulated deficit		(1,516,499	)		(1,603,696	)
Treasury stock, at cost; 539,221 shares at June 30, 2011 and December 31, 2010		(7,479	)		(7,479	)
Total shareholders’ equity		1,646,733			1,540,552
Total liabilities and shareholders’ equity	$	3,659,114		$	3,477,420

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(in thousands, except per share data)	2011			2010			2011			2010
Revenues:
Oil and natural gas	$	206,828		$	118,344		$	368,056		$	249,338
Costs and expenses:
Oil and natural gas production		27,145			31,024			51,789			58,082
Gathering and transportation		19,504			12,873			36,790			23,986
Depreciation, depletion and amortization		85,412			45,339			153,342			84,157
Accretion of discount on asset retirement obligations		933			1,001			1,790			2,090
General and administrative		23,137			25,866			46,560			52,285
Gain on divestitures and other operating items		1,669			(574,946	)		4,126			(575,353	)
Total costs and expenses		157,800			(458,843	)		294,397			(354,753	)
Operating income		49,028			577,187			73,659			604,091
Other income (expense):
Interest expense		(13,679	)		(14,476	)		(28,495	)		(25,110	)
Gain on derivative financial instruments		43,273			707			46,694			99,856
Other income		202			57			362			117
Equity income		3,538			5,290			12,083			5,379
Total other income (expense)		33,334			(8,422	)		30,644			80,242
Income before income taxes		82,362			568,765			104,303			684,333
Income tax expense		0			4,452			0			4,452
Net income	$	82,362		$	564,313		$	104,303		$	679,881
Earnings per common share:
Basic
Net income	$	0.39		$	2.66		$	0.49		$	3.20
Weighted average common shares outstanding		213,888			212,497			213,710			212,293
Diluted
Net income	$	0.38		$	2.62		$	0.48		$	3.15
Weighted average common and common equivalent shares outstanding		217,513			215,498			217,313			215,520

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended June 30,
(in thousands)	2011			2010
Operating Activities:
Net income	$	104,303		$	679,881
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		153,342			84,157
Stock option compensation expense		5,087			8,463
Accretion of discount on asset retirement obligations		1,790			2,090
Gain on divestitures		0			(574,878	)
Income from equity investments		(12,083	)		(5,379	)
Non-cash change in fair value of derivatives		3,458			21,711
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		3,747			3,847
Effect of changes in:
Accounts receivable		(48,445	)		(65,218	)
Other current assets		(3,590	)		(4,081	)
Accounts payable and other current liabilities		20,424			30,353
Net cash provided by operating activities		228,033			181,853
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(474,838	)		(263,361	)
Property acquisitions		(722,032	)		(438,382	)
Proceeds from disposition of property and equipment		410,870			956,296
Investment in equity investments		(10,279	)		(68,500	)
Return of investment in equity investments		125,000			0
Restricted cash		12,502			(16,337	)
Advances to Appalachia JV		(1,309	)		(30,448	)
Deposit on pending acquisitions		464,151			0
Other		(1,250	)		0
Net cash provided by (used in) investing activities		(197,185	)		139,268
Financing Activities:
Borrowings under credit agreements		380,000			1,352,399
Repayments under credit agreements		(377,500	)		(1,622,463	)
Proceeds from issuance of common stock		11,063			9,091
Payment of common stock dividends		(17,106	)		(12,740	)
Settlements of derivative financial instruments with a financing element		—			(907	)
Deferred financing costs and other		(6,348	)		(16,881	)
Net cash provided by (used in) financing activities		(9,891	)		(291,501	)
Net increase in cash		20,957			29,620
Cash at beginning of period		44,229			68,407
Cash at end of period	$	65,186		$	98,027
Supplemental Cash Flow Information:
Cash interest payments	$	37,564		$	25,520
Income tax payments	$	1,458		$	0
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	2,800		$	2,175
Capitalized interest	$	15,748		$	6,114
Issuance of common stock for director services	$	34		$	25

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		743		1								9,115					9,116
Share-based compensation												10,638					10,638
Common stock dividends														(12,740	)		(12,740	)
Net income														679,881			679,881
Balance at June 30, 2010		212,648	$	213		0		$	0		$	3,124,991	$	(1,578,721	)	$	1,546,483
Balance at December 31, 2010		213,736	$	214		(539	)	$	(7,479	)	$	3,151,513	$	(1,603,696	)	$	1,540,552
Issuance of common stock		822		1								11,096					11,097
Share-based compensation												7,887					7,887
Common stock dividends														(17,106	)		(17,106	)
Net income														104,303			104,303
Balance at June 30, 2011		214,558	$	215		(539	)	$	(7,479	)	$	3,170,496	$	(1,516,499	)	$	1,646,733

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 funded 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 June 30, 2011, the remaining balance of the Appalachia Carry was approximately $98.1 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, development and production.

• 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.

8

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. This proposal did not represent a definitive offer and there was no assurance that a definitive offer would be made or accepted, that any agreement would be executed or that any transaction would be consummated.

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.

On July 6, 2011, Mr. Miller submitted a new written proposal for a possible transaction in which he and certain indicated financing sources would acquire by merger an approximately 81% interest in EXCO’s common equity at a stated purchase price of $18.50 per share, with each EXCO shareholder receiving $13.52 per share (or approximately 73% of the purchase price) in cash as well as equity in the post-transaction EXCO with a stated value of $4.98 per share (or approximately 27% of the purchase price), subject to rights of election and pro ration. As part of the financing for the proposed transaction, Mr. Miller’s proposal contemplated the issuance of $300.0 million of perpetual convertible preferred stock which, if not successfully issued, would result in an adjustment to the cash and stock mix received by EXCO shareholders. The July 6, 2011 proposal did not provide any financing commitments.

On July 8, 2011, after consultation with the independent financial and legal advisors, the special committee released a statement that its review of strategic alternatives did not result in any firm proposal or any other proposal that was in the best interests of the Company and its shareholders and that they had terminated the review process. See “Note 16. Acquisition proposal” for further information regarding the proposal.

The accompanying Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010, the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010, the Condensed Consolidated Statements of Cash Flows and the Condensed Consolidated Statements of Changes in Shareholders’ Equity for the six months ended June 30, 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 June 30, 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, as amended, for the year ended December 31, 2010.

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year. Certain prior quarter amounts have been reclassified to conform to current quarter reporting.

2. Significant 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. On July 14, 2011 we finalized the purchase price for the Chief Transaction at $454.4 million, or $227.2 million net to us.

9

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 $82.0 million ($41.0 million net to us), or the Appalachia Transaction.

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, or the Haynesville Shale Acquisition. On May 12, 2011, BG Group elected to participate in this acquisition for its 50% share in accordance with contracts covering our East Texas/North Louisiana JV and funded us $112.6 million.

Amendment of the EXCO Resources Credit Agreement

On April 1, 2011, we entered into the Third Amendment to our credit agreement, or 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 the London Interbank Offered Rate, or LIBOR, plus 150 bps to LIBOR plus 250 bps, or from Alternate 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 EXCO Resources Credit 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.

TGGT incident

On May 28, 2011, an incident occurred at a TGGT amine treating facility which resulted in the immediate shut-down of two treating facilities. While TGGT has an ongoing investigation into causes of the incident, they have recorded a $12.0 million impairment ($6.0 million net to us) in the second quarter of 2011. The majority of this impairment charge is expected to be offset in the future by insurance recovery. This impairment, along with the net impact to their income, caused an estimated $7.8 million negative impact in our equity method income for the second quarter of 2011. TGGT has ordered temporary treating units and through temporary treating facilities, TGGT expects a full resumption of its treating capacity during the third quarter of 2011. TGGT expects to have its permanent treating facility fully operational late in the fourth quarter of 2011. We incurred approximately 23 Mmcfe per day of curtailed net volumes in the second quarter of 2011 as a result of this incident.

3. Recent accounting pronouncements

On May 12, 2011, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2011-04 -Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, or ASU 2011-04. ASU 2011-04 clarifies the FASB’s intent about the application of existing fair value measurement requirements and changes particular principles or requirements for measuring fair value or for disclosing information about fair value measurements. We anticipate the update will impact our fair value disclosures, specifically the classification of our senior notes, whose fair value is disclosed, but not reported on our balance sheet. This update is effective during interim and annual periods beginning after December 15, 2011, at which time we will adopt the update.

On June 16, 2011 the FASB issued ASU No. 2011-05 Comprehensive Income (Topic 220): Presentation of Comprehensive Income, or ASU 2011-05. This ASU requires entities to report items of other comprehensive income on either part of a single contiguous statement of comprehensive income or in a separate statement of comprehensive income immediately following the statement of income. While early adoption is permitted, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and must be applied retrospectively. Presently, we do not have any transactions which require the reporting of comprehensive income; therefore, we do not anticipate any immediate impact from this pronouncement.

10

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, as amended, for the year ended December 31, 2010.

5. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the six months ended June 30, 2011:

(in thousands)
Asset retirement obligation at January 1, 2011	$	50,292
Activity during the six months ended June 30, 2011:
Adjustment to liability due to acquisitions		1,684
Liabilities incurred during the period		2,805
Liabilities settled during the period		(104	)
Adjustment to liability due to sales		(936	)
Accretion of discount		1,790
Asset retirement obligations at June 30, 2011		55,531
Less current portion		(1,279	)
Long-term portion	$	54,252

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 natural gas properties, properties under development, and major development projects, collectively totaled $783.6 million and $599.4 million as of June 30, 2011 and December 31, 2010, respectively, and are not subject to depletion. The increase in our unproved properties between December 31, 2010 and June 30, 2011 was due primarily to properties purchased in the Chief Transaction, the Appalachia Transaction and the Haynesville Shale Acquisition. 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 FASB ASC Subtopic 835-20 for Capitalization of Interest. We capitalize interest upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. When the unproved property costs are moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we cease capitalizing interest.

We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool, excluding the book value of unproved properties, and all estimated future development costs are divided by the total estimated quantities of Proved Reserves. This rate is applied to our total production for the quarter, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our exploration, exploitation and development activities.

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

Pursuant to Rule 4-10(c)(4) of Regulation S-X, at the end of each quarterly period, companies that use the full cost method of accounting for their oil and natural gas properties must compute a limitation on capitalized costs, or ceiling test. The ceiling test involves comparing the net book value of the full cost pool, after taxes, to the full cost ceiling limitation defined below. In the event the full cost ceiling is less than the full cost pool, we must record a ceiling test write-down of our oil and natural gas properties to the value of the full cost ceiling. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying average prices as prescribed by the SEC Release No. 33-8995, less estimated future expenditures (based on current costs) to develop and produce the Proved Reserves, discounted at 10%, plus the cost of properties not being amortized and the lower of cost or estimated fair value of unproved properties included in the costs being amortized, net of income tax effects.

The ceiling test is computed using the simple average spot price for the trailing twelve month period using the first day of each month. For the period ended June 30, 2011, the trailing twelve month reference price was $90.09 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma and $4.21 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 for the three or six months ended June 30, 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 and six months ended June 30, 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 and six months ended June 30, 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 583,371 and 1,300,320 antidilutive common stock equivalents from the three months ended June 30, 2011 and 2010, respectively, from computations of diluted earnings per share and 571,992 and 869,561 antidilutive common stock equivalents from the six months ended June 30, 2011 and 2010, respectively, from computations of diluted earnings per share.

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

	Three months ended June 30,				Six months ended June 30,
(in thousands, except per share amounts)	2011		2010		2011		2010
Basic income per common share:
Net income	$	82,362	$	564,313	$	104,303	$	679,881
Shares:
Weighted average number of common shares outstanding		213,888		212,497		213,710		212,293
Basic income per common share:
Net income per common share	$	0.39	$	2.66	$	0.49	$	3.20
Diluted income per share:
Net income	$	82,362	$	564,313	$	104,303	$	679,881
Shares:
Weighted average number of common shares outstanding		213,888		212,497		213,710		212,293
Dilutive effect of stock options		3,625		3,001		3,603		3,227
Weighted average number of common shares and common stock equivalent shares outstanding		217,513		215,498		217,313		215,520
Diluted income per share:
Net income per common share	$	0.38	$	2.62	$	0.48	$	3.15

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 June 30, 2011 is $21.3 million over a weighted average period of 1.6 years.

The following is a reconciliation of our stock option expense for the three and six months ended June 30, 2011 and 2010:

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2011		2010		2011		2010
General and administrative expense	$	2,362	$	3,603	$	4,947	$	7,862
Lease operating expense		57		251		140		601
Total share-based compensation expense		2,419		3,854		5,087		8,463
Share-based compensation capitalized		1,420		1,070		2,800		2,175
Total share-based compensation	$	3,839	$	4,924	$	7,887	$	10,638

During the six months ended June 30, 2011, options to purchase 75,000 shares of common stock were granted under the 2005 Incentive Plan at prices ranging from $20.16 to $20.78 per share with fair values ranging from $11.32 to $11.62 per share. During the six months ended June 30, 2010, options to purchase 364,350 shares of common stock were granted under the 2005 Incentive Plan at prices ranging from $16.34 to $22.22 per share with fair values ranging from $9.07 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 June 30, 2011 and December 31, 2010, there were 2,111,375 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 six months ended June 30, 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

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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.

Fair Value of Derivative Financial Instruments

(in thousands)	Balance Sheet location	June 30, 2011			December 31, 2010
Commodity contracts	Derivative financial instruments - Current assets	$	69,187		$	73,176
Commodity contracts	Derivative financial instruments - Long-term assets		21,992			23,722
Commodity contracts	Derivative financial instruments - Current liabilities		(2,552	)		(3,775	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(3,162	)		(4,200	)
Net derivatives		$	85,465		$	88,923

The Effect of Derivative Financial Instruments

		Three months ended June 30,				Six months ended June 30,
(in thousands)	Statement of Operations location	2011		2010		2011		2010
Commodity contracts (1)	Gain on derivative financial instruments	$	43,273	$	707	$	46,694	$	99,856
Interest rate contracts (2)	Interest income (expense)		—		—		—		(45	)
Net gain		$	43,273	$	707	$	46,694	$	99,811

(1) Included in these amounts are net cash receipts of $23,217 and $50,152 for the three and six months ended June 30, 2011, respectively, and net cash receipts of $46,538 and $123,585 for the three and six months ended June 30, 2010, respectively.

(2) Included in these amounts are net cash payments of $0 and $2,063 for the three and six months ended June 30, 2010. Our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of June 30, 2011.

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 currently included in income 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, was a gain of $20.1 million and a loss of $45.8 million for the three months ended June 30, 2011 and 2010, respectively, and losses of $3.5 million and $23.7 million for the six months ended June 30, 2011 and 2010, respectively. The unrealized fair value adjustment included in “Interest expense,” which does not impact cash flows, was a gain of $2.0 million for the six months ended June 30, 2010. There was no impact for the three and six months ended June 30, 2011 and for the three months ended June 30, 2010, as our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of June 30, 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 June 30, 2011:

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at June 30, 2011
Natural gas:
Swaps:
Remainder of 2011		61,640	$	5.17	$	42,664
2012		78,690		5.29		35,527
2013		5,475		5.99		4,475
Total natural gas		145,805				82,666
Oil:
Swaps:
Remainder of 2011		276		111.32		3,971
2012		275		95.70		(1,172	)
Total oil		551				2,799
Total oil and natural gas derivatives					$	85,465

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 June 30, 2011, the average forward NYMEX oil prices per Bbl for the remainder of 2011 and for 2012 were $96.90 and $100.04, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2011 and for 2012 were $4.50 and $4.84, respectively.

Our derivative financial instruments used to mitigate price volatility covered approximately 53.4% and 54.0% for the three and six months ended June 30, 2011, respectively, and approximately 54.5% and 60.1% for the three and six months ended June 30, 2010, respectively, of our total equivalent Mcfe production.

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.

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Fair value of derivative financial instruments

The following table presents a summary of the estimated fair value of our derivative financial instruments as of June 30, 2011 and December 31, 2010. During the six months ended June 30, 2011, there were no changes in the fair value level classifications.

	June 30, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	85,465	$	—	$	85,465
	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 LIBOR curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

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

Oil derivatives. Our oil derivatives are swap contracts for notional Bbls of oil at fixed NYMEX West Texas Intermediate (WTI) oil prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil, and (iii) the applicable estimated credit-adjusted risk-free rate curve, as described above.

Natural gas derivatives. Our natural gas derivatives are swap contracts for notional Mmbtus of gas at posted price indexes, including NYMEX Henry Hub (HH) swap contracts. The asset and liability values attributable to our natural gas derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH for natural gas swaps and 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 the 2018 Notes, was $750.0 million with a carrying amount of $739.8 million as of June 30, 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)	June 30, 2011			December 31, 2010
EXCO Resources Credit Agreement	$	851,500		$	849,000
2018 Notes		750,000			750,000
Unamortized discount on 2018 Notes		(10,212	)		(10,731	)
Total debt	$	1,591,288		$	1,588,269

As of June 30, 2011, we had total debt outstanding of approximately $1.6 billion consisting of borrowings under the EXCO Resources Credit Agreement of $851.5 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

As of June 30, 2011, the EXCO Resources Credit Agreement had a borrowing base of $1.5 billion, with $851.5 million of outstanding indebtedness and $639.0 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 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), was increased by 0.5 and can be no greater than 4.0 to 1.0. The maturity date was also 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 our common stock, of which $7.5 million has been utilized as of June 30, 2011.

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 June 30, 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.

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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 2011 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 June 30, 2011, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at June 30, 2011 was $10.2 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $750.0 million on June 30, 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.

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

12. Dividends

On June 1, 2011, our Board of Directors approved a cash dividend of $0.04 per share for the second quarter of 2011. The total cash dividend of $8.6 million was paid on June 30, 2011 to holders of record on June 15, 2011. Dividends paid in 2011 total $17.1 million as of June 30, 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, the indenture governing the 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 and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial deferred tax assets primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Also, we have financial tax net operating losses as a result of our drilling programs. For the three and six months ended June 30, 2011, we estimate that we have utilized $32.9 million and $41.7 million, respectively, of our accumulated valuation allowance. As a result of cumulative financial operating losses, we have recognized net valuation allowances of

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approximately $345.9 million as of June 30, 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 four entities with BG Group, which are described below. We use the equity method of accounting for each investment.

• We have a 50% ownership in TGGT, which holds interests in midstream assets in East Texas and North Louisiana. 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. On May 28, 2011, an incident occurred at a TGGT amine treating facility which resulted in the immediate shut-down of two treating facilities. While TGGT has an ongoing investigation into causes of the incident, they have recorded a $12.0 million impairment ($6.0 million net to us) in the second quarter 2011. This impairment, along with the net impact to their income, caused an estimated $7.8 million negative impact in our equity method income for the second quarter of 2011.

• 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 half of 2011, EXCO and BG Group each contributed $2.7 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, and capital contributions for OPCO’s drilling and operating budget needs.

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

• We own a 50% interest in a joint venture that manages the acreage and various facilities that were purchased in conjunction with the Haynesville Shale Acquisition.

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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)	June 30, 2011		December 31, 2010
Assets:
Total current assets	$	155,560	$	120,475
Property and equipment, net		985,248		873,228
Other assets		4,068		6,143
Total assets	$	1,144,876	$	999,846
Liabilities and members’ equity:
Total current liabilities	$	141,809	$	145,006
Total long-term debt		367,142		—
Total long-term liabilities		3,791		10,092
Total members’ equity		632,134		844,748
Total liabilities and members’ equity	$	1,144,876	$	999,846

	Three months ended				Six months ended
(in thousands)	June 30, 2011		June 30, 2010		June 30, 2011		June 30, 2010
Revenues:
Oil and natural gas	$	130	$	25	$	256	$	25
Midstream		61,458		43,568		115,640		75,352
Total revenues		61,588		43,593		115,896		75,377
Costs and expenses:
Oil and natural gas production		378		42		539		42
Midstream operating		26,713		25,161		50,775		50,884
Other expenses		21,468		3,879		28,560		7,578
Depreciation, depletion, and amortization		6,508		4,758		13,013		7,680
Total costs and expenses		55,067		33,840		92,887		66,184
Income before income taxes		6,521		9,753		23,009		9,193
Income tax expense		384		92		719		159
Net income	$	6,137	$	9,661	$	22,290	$	9,034
EXCO’s share of equity income before amortization	$	3,069	$	4,831	$	11,145	$	4,517
Amortization of the difference in the historical basis of our contribution	$	469		459	$	938		862
EXCO’s share of equity income after amortization	$	3,538	$	5,290	$	12,083	$	5,379

(in thousands)	June 30, 2011			December 31, 2010
Equity investments	$	273,632		$	379,001
Basis adjustment (1)		45,755			45,755
Cumulative amortization of basis adjustment (2)		(3,320	)		(2,382	)
EXCO’s 50% interest in equity investments	$	316,067		$	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 June 30, 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. On July 8, 2011, the special committee of our Board of Directors terminated their strategic review process. Reinstatement of the repurchase program is currently being evaluated.

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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 did not represent a definitive offer and there was no assurance that a definitive offer would be made or accepted, that any agreement would be executed or that any transaction would 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 sought 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 attorneys’ 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.

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 three 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 one derivative action is 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 entered into similar agreements with other parties interested in exploring a possible acquisition of the Company.

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. 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.

21

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 above). 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 it would 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 would 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 was no assurance that the special committee’s exploration of strategic alternatives would result in a sale of the Company or any other transaction.

On July 6, 2011, Mr. Miller submitted a new written proposal for a possible transaction in which he and certain indicated financing sources would acquire by merger an approximate 81% interest in EXCO’s common equity at a stated purchase price of $18.50 per share, with each EXCO shareholder receiving $13.52 per share (or approximately 73% of the purchase price) in cash as well as equity in the post-transaction EXCO with a stated value of $4.98 per share (or approximately 27% of the purchase price), subject to rights of election and pro ration. As part of the financing for the proposed transaction, Mr. Miller’s proposal contemplated the issuance of $300 million of perpetual convertible preferred stock which, if not successfully issued, would result in an adjustment to the cash and stock mix received by EXCO shareholders. The July 6, 2011 proposal did not provide any financing commitments.

On July 8, 2011, after consultation with the independent financial and legal advisors, the special committee released a statement that its review of strategic alternatives did not result in any firm proposal or any other proposal that was in the best interests of the Company and its shareholders and that they had terminated the review process.

17. Condensed consolidating financial statements

As of June 30, 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 June 30, 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 $270.9 million of equity method investments, or 7.4% of our total assets and contributed $12.2 million of equity method income; and

• Our non-guarantor, unrestricted subsidiaries that are wholly owned represented approximately $16.7 million of our total assets and $0.1 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.

22

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.

23

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

June 30, 2011

(in thousands)	Resources			Guarantor subsidiaries			Non-Guarantor subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	113,054		$	(47,868	)	$	0	$	0		$	65,186
Restricted cash		0			149,215			0		0			149,215
Other current assets		87,865			261,850			9		0			349,724
Total current assets		200,919			363,197			9		0			564,125
Equity investment		0			0			273,632		0			273,632
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		29,394			754,227			0		0			783,621
Proved developed and undeveloped oil and natural gas properties		428,141			2,610,506			0		0			3,038,647
Accumulated depletion		(305,194	)		(1,151,031	)		0		0			(1,456,225	)
Oil and natural gas properties, net		152,341			2,213,702			0		0			2,366,043
Gas gathering, office and field equipment, net		29,326			128,541			16,712		0			174,579
Investments in and advances to affiliates		1,046,407			92,973			0		(1,139,380	)		0
Deferred financing costs, net		33,822			0			0		0			33,822
Derivative financial instruments		14,869			7,123			0		0			21,992
Goodwill		38,100			180,156			0		0			218,256
Other assets		1			6,664			0		0			6,665
Total assets	$	1,515,785		$	2,992,356		$	290,353	$	(1,139,380	)	$	3,659,114
Liabilities and shareholders’ equity
Current liabilities	$	66,172		$	290,747		$	123	$	0		$	357,042
Long-term debt		1,591,288			0			0		0			1,591,288
Deferred income taxes		0			0			0		0			0
Other liabilities		9,114			54,937			0		0			64,051
Payable to parent		(1,797,522	)		1,786,953			10,569		0			0
Total shareholders’ equity		1,646,733			859,719			279,661		(1,139,380	)		1,646,733
Total liabilities and shareholders’ equity	$	1,515,785		$	2,992,356		$	290,353	$	(1,139,380	)	$	3,659,114

24

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	)	$	0	$	0		$	44,229
Restricted cash		0			161,717			0		0			161,717
Other current assets		83,913			230,590			11		0			314,514
Total current assets		160,676			359,773			11		0			520,460
Equity investment		0			0			379,001		0			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			0		0			599,409
Proved developed and undeveloped oil and natural gas properties		385,357			1,985,605			0		0			2,370,962
Accumulated depletion		(295,453	)		(1,016,763	)		0		0			(1,312,216	)
Oil and natural gas properties, net		127,722			1,530,433			0		0			1,658,155
Gas gathering, office and field equipment, net		28,837			131,276			16,193		0			176,306
Investments in and advances to affiliates		964,806			92,973			0		(1,057,779	)		0
Deferred financing costs, net		30,704			0			0		0			30,704
Derivative financial instruments		13,665			10,057			0		0			23,722
Goodwill		38,100			180,156			0		0			218,256
Other assets		3			470,813			0		0			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	$	0		$	285,698
Long-term debt		1,588,269			0			0		0			1,588,269
Deferred income taxes		0			0			0		0			0
Other liabilities		10,234			52,667			0		0			62,901
Payable to parent		(1,825,196	)		1,821,530			3,666		0			0
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

25

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	24,004		$	182,824		$	0		$	0		$	206,828
Costs and expenses:
Oil and natural gas production		5,060			22,085			0			0			27,145
Gathering and transportation		0			19,504			0			0			19,504
Depreciation, depletion and amortization		7,204			77,775			433			0			85,412
Accretion of discount on asset retirement obligations		107			826			0			0			933
General and administrative		4,600			18,538			(1	)		0			23,137
Gain on divestitures and other operating items		1,987			(24	)		(294	)		0			1,669
Total costs and expenses		18,958			138,704			138			0			157,800
Operating income (loss)		5,046			44,120			(138	)		0			49,028
Other income (expense):
Interest expense		(13,673	)		(6	)		0			0			(13,679	)
Gain on derivative financial instruments		36,006			7,267			0			0			43,273
Other income (expense)		101			101			0			0			202
Equity income		0			0			3,538			0			3,538
Equity in earnings of subsidiaries		54,882			0			0			(54,882	)		0
Total other income (expense)		77,316			7,362			3,538			(54,882	)		33,334
Income (loss) before income taxes		82,362			51,482			3,400			(54,882	)		82,362
Income tax expense		0			0			0			0			0
Net income (loss)	$	82,362		$	51,482		$	3,400		$	(54,882	)	$	82,362

26

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended June 30, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Oil and natural gas	$	16,077		$	99,220		$	3,047	$	0		$	118,344
Costs and expenses:
Oil and natural gas production		3,895			26,716			413		0			31,024
Gathering and transportation		0			12,699			174		0			12,873
Depreciation, depletion and amortization		5,697			38,624			1,018		0			45,339
Accretion of discount on asset retirement obligations		85			915			1		0			1,001
General and administrative		6,612			19,254			0		0			25,866
Gain on divestitures and other operating items		2,766			(577,712	)		0		0			(574,946	)
Total costs and expenses		19,055			(479,504	)		1,606		0			(458,843	)
Operating income (loss)		(2,978	)		578,724			1,441		0			577,187
Other income (expense):
Interest expense		(11,301	)		(3,175	)		0		0			(14,476	)
Gain (loss) on derivative financial instruments		3,088			(2,381	)		0		0			707
Other income (expense)		4,155			(4,098	)		0		0			57
Equity income		0			0			5,290		0			5,290
Equity in earnings of subsidiaries		575,801			0			0		(575,801	)		0
Total other income (expense)		571,743			(9,654	)		5,290		(575,801	)		(8,422	)
Income (loss) before income taxes		568,765			569,070			6,731		(575,801	)		568,765
Income tax expense		4,452			0			0		0			4,452
Net income (loss)	$	564,313		$	569,070		$	6,731	$	(575,801	)	$	564,313

27

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	47,390		$	320,666		$	0		$	0		$	368,056
Costs and expenses:
Oil and natural gas production		9,347			42,442			0			0			51,789
Gathering and transportation		0			36,790			0			0			36,790
Depreciation, depletion and amortization		13,770			138,768			804			0			153,342
Accretion of discount on asset retirement obligations		208			1,582			0			0			1,790
General and administrative		9,316			37,245			(1	)		0			46,560
Gain on divestitures and other operating items		4,602			530			(1,006	)		0			4,126
Total costs and expenses		37,243			257,357			(203	)		0			294,397
Operating income		10,147			63,309			203			0			73,659
Other income (expense):
Interest expense		(27,237	)		(1,258	)		0			0			(28,495	)
Gain on derivative financial instruments		39,607			7,087			0			0			46,694
Other income (expense)		185			177			0			0			362
Equity income		0			0			12,083			0			12,083
Equity in earnings of subsidiaries		81,601			0			0			(81,601	)		0
Total other income (expense)		94,156			6,006			12,083			(81,601	)		30,644
Income (loss) before income taxes		104,303			69,315			12,286			(81,601	)		104,303
Income tax expense		0			0			0			0			0
Net income (loss)	$	104,303		$	69,315		$	12,286		$	(81,601	)	$	104,303

28

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the six months ended June 30, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Oil and natural gas	$	33,722		$	211,888		$	3,728	$	0		$	249,338
Costs and expenses:
Oil and natural gas production		7,851			49,870			361		0			58,082
Gathering and transportation		0			23,694			292		0			23,986
Depreciation, depletion and amortization		12,847			70,064			1,246		0			84,157
Accretion of discount on asset retirement obligations		168			1,921			1		0			2,090
General and administrative		14,257			38,028			0		0			52,285
Gain on divestitures and other operating items		2,164			(577,517	)		0		0			(575,353	)
Total costs and expenses		37,287			(393,940	)		1,900		0			(354,753	)
Operating income (loss)		(3,565	)		605,828			1,828		0			604,091
Other income (expense):
Interest expense		(18,375	)		(6,735	)		0		0			(25,110	)
Gain on derivative financial instruments		33,942			65,914			0		0			99,856
Other income (expense)		10,329			(10,212	)		0		0			117
Equity income		0			0			5,379		0			5,379
Equity in earnings of subsidiaries		662,002			0			0		(662,002	)		0
Total other income (expense)		687,898			48,967			5,379		(662,002	)		80,242
Income (loss) before income taxes		684,333			654,795			7,207		(662,002	)		684,333
Income tax expense		4,452			0			0		0			4,452
Net income (loss)	$	679,881		$	654,795		$	7,207	$	(662,002	)	$	679,881

29

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	54,364		$	172,738		$	931		$	0	$	228,033
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment and property acquisitions		(36,139	)		(1,156,595	)		(4,136	)		0		(1,196,870	)
Proceeds from disposition of property and equipment		57			410,813			0			0		410,870
Investment in equity investments		0			(10,279	)		0			0		(10,279	)
Return of investment in equity investments		0			125,000			0			0		125,000
Restricted cash		0			12,502			0			0		12,502
Advances to Appalachia JV		0			(1,309	)		0			0		(1,309	)
Deposit on pending acquisitions		0			464,151			0			0		464,151
Other		0			(1,250	)		0			0		(1,250	)
Advances/investments with affiliates		27,900			(31,105	)		3,205			0		0
Net cash used in investing activities		(8,182	)		(188,072	)		(931	)		0		(197,185	)
Financing Activities:
Borrowings under credit agreement		380,000			0			0			0		380,000
Repayments under credit agreement		(377,500	)		0			0			0		(377,500	)
Proceeds from issuance of common stock		11,063			0			0			0		11,063
Payment of common stock dividends		(17,106	)		0			0			0		(17,106	)
Deferred financing costs and other		(6,348	)		0			0			0		(6,348	)
Net cash used in financing activities		(9,891	)		0			0			0		(9,891	)
Net increase (decrease) in cash		36,291			(15,334	)		0			0		20,957
Cash at the beginning of the period		76,763			(32,534	)		0			0		44,229
Cash at end of period	$	113,054		$	(47,868	)	$	0		$	0	$	65,186

30

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the six months ended June 30, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	58,315		$	135,348		$	(11,810	)	$	0	$	181,853
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(19,885	)		(478,113	)		(203,745	)		0		(701,743	)
Restricted cash		0			(16,337	)		0			0		(16,337	)
Investment in equity investments		0			(68,500	)		0			0		(68,500	)
Proceeds from dispositions		11,348			944,948			0			0		956,296
Advances to Appalachia JV		0			(30,448	)		0			0		(30,448	)
Advances/investments with affiliates		223,570			(439,365	)		215,795			0		0
Net cash provided by (used in) investing activities		215,033			(87,815	)		12,050			0		139,268
Financing Activities:
Borrowings under credit agreements		1,302,437			49,962			0			0		1,352,399
Repayments under credit agreements		(1,597,482	)		(24,981	)		0			0		(1,622,463	)
Proceeds from issuance of common stock, net		9,091			0			0			0		9,091
Payment of common stock dividends		(12,740	)		0			0			0		(12,740	)
Settlement of derivative financial instruments with a financing element		(907	)		0			0			0		(907	)
Deferred financing costs and other		(16,881	)		0			0			0		(16,881	)
Net cash provided by (used in) financing activities		(316,482	)		24,981			0			0		(291,501	)
Net increase (decrease) in cash		(43,134	)		72,514			240			0		29,620
Cash at beginning of period		47,412			20,995			0			0		68,407
Cash at end of period	$	4,278		$	93,509		$	240		$	0	$	98,027

31

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;

• 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;

• fluctuations in interest rates; and

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

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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, as amended, for the year ended December 31, 2010.

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. 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 funded 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 June 30, 2011, the remaining balance of the Appalachia Carry was approximately $98.1 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 $851.5 million was drawn as of July 27, 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.

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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. This proposal did not represent a definitive offer and there was no assurance that a definitive offer would be made or accepted, that any agreement would be executed or that any transaction would be consummated.

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.

On July 6, 2011, Mr. Miller submitted a new written proposal for a possible transaction in which he and certain indicated financing sources would acquire by merger an approximately 81% interest in EXCO’s common equity at a stated purchase price of $18.50 per share, with each EXCO shareholder receiving $13.52 per share (or approximately 73% of the purchase price) in cash as well as equity in the post-transaction EXCO with a stated value of $4.98 per share (or approximately 27% of the purchase price), subject to rights of election and pro ration. As part of the financing for the proposed transaction, Mr. Miller’s proposal contemplated the issuance of $300 million of perpetual convertible preferred stock which, if not successfully issued, would result in an adjustment to the cash and stock mix received by EXCO shareholders. The July 6, 2011 proposal did not provide any financing commitments.

On July 8, 2011, after consultation with the independent financial and legal advisors, the special committee released a statement that its review of strategic alternatives did not result in any firm proposal or any other proposal that was in the best interests of the Company and its shareholders and that they had terminated the review process. 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 forecasted capital expenditures total $997.0 million, of which $903.4 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 $829.7 million. During the first half of 2011, we spent $436.5 million in East Texas/North Louisiana, $432.6 million of which was in the area of mutual interest with BG Group, or the East Texas/North Louisiana AMI. In Appalachia, our share of planned capital expenditures for the Appalachia JV are expected to total $54.7 million, which excludes $125.0 million of the Appalachia Carry. During the first half of 2011, we spent $21.5 million in Appalachia, which reflects the impact of the Appalachia Carry. As of June 30, 2011, the remaining balance of the Appalachia Carry was approximately $98.1 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 capital distributions of $125.0 million each to us and BG Group. 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 in Appalachia.

For the six months ended June 30, 2011, we produced 82.2 Bcfe of oil and natural gas. Of the amount produced, 72.8 Bcfe were produced in our East Texas/North Louisiana area, 5.6 Bcfe were produced in our Appalachia area and 3.8 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.

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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, as amended, for the year ended December 31, 2010.

Recent events

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. On July 14, 2011, we finalized the purchase price for the Chief Transaction of $454.4 million, or $227.2 million net to us.

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 $82.0 million ($41.0 million net to us), or the Appalachia Transaction.

Amendment of the EXCO Resources Credit Agreement

On April 1, 2011, we entered into the Third Amendment to our credit agreement, or 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 the London Interbank Offered Rate, or 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 EXCO Resources Credit 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, or the Haynesville Shale Acquisition. On May 12, 2011, BG Group elected to participate in this acquisition for its 50% share in accordance with contracts covering our East Texas/North Louisiana JV and funded us $112.6 million.

TGGT incident

On May 28, 2011, an incident occurred at a TGGT amine treating facility which resulted in the immediate shut-down of two treating facilities. While TGGT has an ongoing investigation into causes of the incident, they have recorded a $12.0 million impairment ($6.0 million net to us) in the second quarter 2011. This impairment, along with the net impact to their income, caused an estimated $7.8 million negative impact in our equity method income for the second quarter of 2011. TGGT has ordered temporary treating units and expects resumption of its treating capacity during the third quarter of 2011, with total resumption of treating facilities during the fourth quarter of 2011. We incurred approximately 23 Mmcfe per day of curtailed net volumes in the second quarter of 2011 as a result of this incident.

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Recent accounting pronouncements

On May 12, 2011, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2011-04 -Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, or ASU 2011-04. ASU 2011-04 clarifies the FASB’s intent about the application of existing fair value measurement requirements and changes particular principles or requirements for measuring fair value or for disclosing information about fair value measurements. We anticipate the update will impact our fair value disclosures, specifically the classification of our senior notes, whose fair value is disclosed, but not reported on our balance sheet. This update is effective during interim and annual periods beginning after December 15, 2011, at which time we will adopt the update.

On June 16, 2011 the FASB issued ASU No. 2011-05 Comprehensive Income (Topic 220): Presentation of Comprehensive Income, or ASU 2011-05. This ASU requires entities to report items of other comprehensive income on either part of a single contiguous statement of comprehensive income or in a separate statement of comprehensive income immediately following the statement of income. While early adoption is permitted, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011 and must be applied retrospectively. Presently, we do not have any transactions which require the reporting of comprehensive income; therefore, we do not anticipate any immediate impact from this pronouncement.

Our results of operations

A summary of key financial data for the three and six months ended June 30, 2011 and 2010 related to our results of operations is presented below:

	Three months ended June 30,					Quarter to quarter change 2011-2010			Six months ended June 30,						Period to period change 2011-2010
(dollars in thousands, except per unit prices)	2011		2010						2011			2010
Production:
Oil (Mbbls)		178		168			10			371			327			44
Natural gas (Mmcf)		44,467		25,539			18,928			79,992			48,376			31,616
Total production (Mmcfe) (1)		45,535		26,547			18,988			82,218			50,338			31,880
Oil and natural gas revenues before derivative financial instrument activities:
Oil	$	17,650	$	12,506		$	5,144		$	35,022		$	24,469		$	10,553
Natural gas		189,178		105,838			83,340			333,034			224,869			108,165
Total oil and natural gas revenues	$	206,828	$	118,344		$	88,484		$	368,056		$	249,338		$	118,718
Oil and natural gas derivative financial instruments:
Cash settlements on derivative financial instruments	$	23,217	$	46,538		$	(23,321	)	$	50,152		$	123,585		$	(73,433	)
Non-cash change in fair value of derivative financial instruments		20,056		(45,831	)		65,887			(3,458	)		(23,729	)		20,271
Total derivative financial instrument activities	$	43,273	$	707		$	42,566		$	46,694		$	99,856		$	(53,162	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	99.16	$	74.44		$	24.72		$	94.40		$	74.83		$	19.57
Natural gas (per Mcf)		4.25		4.14			0.11			4.16			4.65			(0.49	)
Natural gas equivalent (per Mcfe)		4.54		4.46			0.08			4.48			4.95			(0.47	)
Costs and expenses:
Oil and natural gas operating costs (2)	$	20,697	$	22,503		$	(1,806	)	$	39,742		$	41,696		$	(1,954	)
Production and ad valorem taxes		6,448		8,521			(2,073	)		12,047			16,386			(4,339	)
Gathering and transportation		19,504		12,873			6,631			36,790			23,986			12,804
Depletion		80,687		41,122			39,565			144,007			75,142			68,865
Depreciation and amortization		4,725		4,217			508			9,335			9,015			320
General and administrative (3)		23,137		25,866			(2,729	)		46,560			52,285			(5,725	)
Interest expense		13,679		14,476			(797	)		28,495			25,110			3,385
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.45	$	0.85		$	(0.40	)	$	0.48		$	0.83		$	(0.35	)
Production and ad valorem taxes		0.14		0.32			(0.18	)		0.15			0.33			(0.18	)
Gathering and transportation		0.43		0.48			(0.05	)		0.45			0.48			(0.03	)
Depletion		1.77		1.55			0.22			1.75			1.49			0.26
Depreciation and amortization		0.10		0.16			(0.06	)		0.11			0.18			(0.07	)
General and administrative		0.51		0.97			(0.46	)		0.57			1.04			(0.47	)
Net income	$	82,362	$	564,313		$	(481,951	)	$	104,303		$	679,881		$	(575,578	)

(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 $0.2 million for the three months ended June 30, 2011 and 2010, respectively, and $0.1 million and $0.6 million for the six months ended June 30, 2011 and 2010, respectively.

(3) Share-based compensation included in general and administrative expenses is $2.4 million and $3.6 million for the three months ended June 30, 2011 and 2010, respectively, and $5.0 million and $7.9 million for the six months ended June 30, 2011 and 2010, respectively.

The following is a discussion of our financial condition and results of operations for the three and six months ended June 30, 2011 and 2010.

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

• the Appalachia JV in 2010;

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• the Chief Transaction, the Appalachia Transaction and the Haynesville Shale Acquisition in 2011;

• 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;

• significant changes in the amount of long-term debt; and

• costs associated with the special committee’s review of strategic alternatives.

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

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other buyers for our production or for any of our newly discovered oil or natural gas reserves, we may shut-in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated. Economic conditions 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.

Summary

For the three months ended June 30, 2011, we reported net income of $82.4 million compared to net income of $564.3 million for the three months ended June 30, 2010. For the six months ended June 30, 2011, we reported net income of $104.3 million compared to net income of $679.9 million for the six months ended June 30, 2010.

The decrease in net income for the three and six months ended June 30, 2011 from the same periods in 2010 is primarily the result of the $574.9 million gain on the sale of a 50% undivided interest in substantially all of our Appalachian oil and natural gas proved and unproved properties and related assets on June 1, 2010, which resulted in the Appalachia JV. In addition, our production volumes have increased significantly as a result of our horizontal drilling program, particularly in our East Texas/North Louisiana area. The higher production volumes have increased our revenues, gathering and transportation expenses, and associated depletion expenses for the three and six month comparison periods. The horizontal wells produce high volumes of natural gas, but require similar expenses to operate as compared to vertical wells. Consequently, operating expenses, on a per Mcfe basis, are trending downward. The impacts of the higher production volumes, increased revenues and related expenses are discussed in detail below.

Oil and natural gas production, revenues, and prices

The following table presents our revenues, production and average sales prices by major producing areas for the three and six months ended June 30, 2011 and 2010:

(dollars in thousands, except per unit rate)	Three months ended June 30,												Quarter to quarter change
	2011						2010
	Production (Mmcfe)		Revenue		$/Mcfe		Production (Mmcfe)		Revenue		$/Mcfe		Production (Mmcfe)			Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana		40,827	$	169,795	$	4.16		22,097	$	90,354	$	4.09		18,730		$	79,441		$	0.07
Appalachia		2,866		13,029		4.55		2,669		11,912		4.46		197			1,117			0.09
Permian and other		1,842		24,004		13.03		1,781		16,078		9.03		61			7,926			4.00
Total		45,535	$	206,828		4.54		26,547	$	118,344		4.46		18,988		$	88,484			0.08
	Six months ended June 30,												Period to period change
	2011						2010
(dollars in thousands, except per unit rate)	Production (Mmcfe)		Revenue		$/Mcfe		Production (Mmcfe)		Revenue		$/Mcfe		Production (Mmcfe)			Revenue			$/Mcfe
Producing region:
East Texas/North Louisiana		72,772	$	295,001	$	4.05		40,850	$	184,349	$	4.51		31,922		$	110,652		$	(0.46	)
Appalachia		5,646		25,666		4.55		6,010		31,266		5.20		(364	)		(5,600	)		(0.65	)
Permian and other		3,800		47,389		12.47		3,478		33,723		9.70		322			13,666			2.77
Total		82,218	$	368,056		4.48		50,338	$	249,338		4.95		31,880		$	118,718			(0.47	)

Production in our East Texas/North Louisiana region for the three and six months ended June 30, 2011 increased by 18.7 Bcfe and 31.9 Bcfe, respectively, from the same period in the prior year. These increases are the result of the continued successful development of our Haynesville shale, which resulted in production increases of 20.8 Bcfe and 35.4 Bcfe for the three and six months ended June 30, 2011 when compared to the same periods in the prior year. The increase in Haynesville production is partially offset by production declines of 1.3 Bcfe and 2.7 Bcfe in our Vernon Field for the three and six months ended June 30, 2011, as compared to the same period in the prior year, and other production declines of 0.8 Bcfe for both the three and six months ended June 30, 2011. The declines in Vernon and other areas are primarily the result of the suspension of vertical drilling operations and normal production declines. 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 and the Appalachia Transaction, offset by declines as a result of the Appalachia JV. Our Permian Basin also experienced production increases due to the resumption of drilling operations during 2010.

For the three months ended June 30, 2011, oil and natural gas revenues were $206.8 million, a 74.8% increase from the oil and natural gas revenues of $118.3 million for the three months ended June 30, 2010. The increase in revenues is primarily a result of the overall increased production in our Haynesville operations and a

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slight increase in equivalent oil and natural gas prices. The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased from $74.44 per Bbl for the three months ended June 30, 2010 to $99.16 per Bbl for the three months ended June 30, 2011, or 33.2%. The average natural gas sales price, excluding the impact of derivative financial instruments, was $4.25 per Mcf for the three months ended June 30, 2011 compared with $4.14 per Mcf for the three months ended June 30, 2010, an increase of 2.7%.

For the six months ended June 30, 2011, oil and natural gas revenues were $368.1 million, a 47.6% increase from the oil and natural gas revenues of $249.3 million for the six months ended June 30, 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 $74.83 per Bbl for the six months ended June 30, 2010 to $94.40 per Bbl for the six months ended June 30, 2011, or 26.2%. The average natural gas sales price, excluding the impact of derivative financial instruments, was $4.16 per Mcf for the six months ended June 30, 2011 compared with $4.65 per Mcf for the six months ended June 30, 2010, a decrease of 10.5%.

The price we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, estimates of oil and natural gas in storage, weather and other seasonal conditions, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. 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 six months ended June 30, 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 $8.0 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 $0.4 million, without considering the effects of derivative financial instruments.

In addition, our production volumes are impacted by shut-in volumes of natural gas due to operational requirements associated with fracture stimulation and other operations on near-by horizontal wells, seasonal supply and demand conditions from end users and general maintenance and repairs to our wells. While these shut-in volumes are typically for short periods of time, they may have impacts to our revenues, cash flows and results of operations. We expect that approximately 7.5% to 10.0% of our Haynesville/Bossier shale production will be shut-in. As discussed below inMidstream operations, an incident occurred at a TGGT amine treating facility in May 2011, which forced two treating facilities to be shut down immediately. As a result of this shutdown, we estimate approximately 23 Mmcfe per day of curtailed net volumes occurred in the second quarter of 2011, and we expect approximately 25-30 Mmcfe per day of curtailed net volumes in the third quarter of 2011, with full restoration of volumes during the fourth quarter of 2011.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three and six months ended June 30, 2011 were $20.7 million and $39.7 million, respectively, compared with $22.5 million and $41.7 million for the three and six months ended June 30, 2010, respectively. The primary reason for the decreases for the three and six month periods reflect reductions in Appalachia related to the formation of the Appalachia JV, decreases in maintenance and service costs, principally in our Vernon Field and decreases arising from various divestitures in 2011 of non-core shallow properties. To further analyze the variances in costs, management reviews the costs on a per Mcfe basis, as we believe this measure excludes the impact of any acquisitions or divestitures and actual operating expense trends due to fluctuating production volume.

As shown in the table below, on a per Mcfe basis, oil and natural gas operating expenses for the three months ended June 30, 2011 decreased $0.40, or 47.1%, per Mcfe from the same period in 2010, with lease operating expenses representing $0.34 per Mcfe of the decrease and workovers and other expense representing $0.06 per Mcfe of the decrease. The net decrease in oil and natural gas operating expenses per Mcfe in East Texas/North Louisiana is primarily due to the Haynesville shale wells, which have a relatively low lease operating rate per Mcfe, partially offset by increased costs in our Vernon Field and Cotton Valley area, which have higher lease operating expense rates per Mcfe, principally due to lower production volumes caused by natural decline. In addition, there were decreases in workovers in our Vernon Field. 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. Operating expenses in the Permian area increased primarily due to higher maintenance and workover expenses.

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(in thousands)		Three months ended June 30,
		2011						2010						Quarter to quarter change
		Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
	��
Producing region:
East Texas/North Louisiana		$	11,398	$	2,506	$	13,904	$	12,616	$	2,785	$	15,401	$	(1,218	)	$	(279	)	$	(1,497	)
Appalachia			3,668		—		3,668		4,472		80		4,552		(804	)		(80	)		(884	)
Permian and other			2,875		250		3,125		2,335		215		2,550		540			35			575
Total		$	17,941	$	2,756	$	20,697	$	19,423	$	3,080	$	22,503	$	(1,482	)	$	(324	)	$	(1,806	)
(per Mcfe)		Three months ended June 30,
		2011						2010						Quarter to quarter change
		Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana		$	0.28	$	0.06	$	0.34	$	0.57	$	0.13	$	0.70	$	(0.29	)	$	(0.07	)	$	(0.36	)
Appalachia			1.28		—		1.28		1.68		0.03		1.71		(0.40	)		(0.03	)		(0.43	)
Permian and other			1.56		0.14		1.70		1.31		0.12		1.43		0.25			0.02			0.27
Total		$	0.39	$	0.06	$	0.45	$	0.73	$	0.12	$	0.85	$	(0.34	)	$	(0.06	)	$	(0.40	)

On a per Mcfe basis, oil and natural gas operating expenses for the six months ended June 30, 2011 decreased $0.35, or 42.2%, per Mcfe from the same period in 2010, with lease operating expenses representing $0.31 of the decrease and workovers and other expense representing $0.04 per Mcfe of the decrease. While there was a slight increase in total oil and natural gas operating expenses for the East Texas/North Louisiana region, there was an overall decrease in operating expenses per Mcfe in East Texas/North Louisiana as a result of increased production in our Haynesville shale, which has a relatively low lease operating rate per Mcfe. These low lease operating rates were partially offset by increased 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. These increases are offset by the Permian region due to increased activity related to resumption of our drilling program in the third quarter of 2010.

(in thousands)	Six months ended June 30,
	2011						2010						Period to period change
	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	22,400	$	5,022	$	27,422	$	23,145	$	4,175	$	27,320	$	(745	)	$	847		$	102
Appalachia		6,584		—		6,584		9,259		216		9,475		(2,675	)		(216	)		(2,891	)
Permian and other		5,403		333		5,736		4,469		432		4,901		934			(99	)		835
Total	$	34,387	$	5,355	$	39,742	$	36,873	$	4,823	$	41,696	$	(2,486	)	$	532		$	(1,954	)
(per Mcfe)	Six months ended June 30,
	2011						2010						Period to period change
	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	0.31	$	0.07	$	0.38	$	0.57	$	0.10	$	0.67	$	(0.26	)	$	(0.03	)	$	(0.29	)
Appalachia		1.17		—		1.17		1.54		0.04		1.58		(0.37	)		(0.04	)		(0.41	)
Permian and other		1.42		0.09		1.51		1.29		0.12		1.41		0.13			(0.03	)		0.10
Total	$	0.42	$	0.06	$	0.48	$	0.73	$	0.10		0.83	$	(0.31	)	$	(0.04	)	$	(0.35	)

Midstream operations

We own a 50% membership interest in two midstream joint ventures, TGGT and Appalachia Midstream JV. The joint venture business activities relate to fees earned from gathering, treating and compression of natural gas and purchases/resales of natural gas. Our joint ventures do not own any natural gas processing facilities. We use the equity method of accounting for both of our midstream joint ventures.

TGGT holds our East Texas/North Louisiana midstream assets, exclusive of the Vernon Field gathering assets. 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.

TGGT, whose primary customers are EXCO and BG Group, 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.

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TGG operates amine, glycol, and H₂S treating facilities, which treat natural gas in order to meet pipeline quality specifications for downstream transportation. TGG’s system, which has access to 14 interstate and intrastate pipeline markets, has approximately 126 miles of pipeline comprised of 12, 16, and 20-inch diameter pipe in its legacy East Texas area and 27 miles of pipeline comprised of 36-inch diameter pipe in the North Louisiana area. Additionally, TGG has initiated major midstream expansion efforts in the Shelby Area in East Texas where we are installing gathering lines and treating facilities necessary to meet the throughput volume increase expected from this area. TGGT expects completion by year end 2011. Once completed, this expansion is expected to increase throughput and treating capacity by approximately 500 Mmcf per day.

On May 28, 2011, an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana that forced the treating facility to shut down immediately and, as a precautionary measure, shut down of another TGGT amine treating facility located in DeSoto Parish with similar specifications. While TGGT has an ongoing investigation into causes of the incident, they have ordered temporary treating units and expects resumption of treating capacity during the third quarter of 2011, with a total resumption of treating facilities during the fourth quarter of 2011. The estimated second quarter of 2011 impact to TGGT resulting from this incident was a $3.5 million decrease to their revenues and a $0.1 million increase in their operating expenses. The anticipated impact for the remainder of the year is a $3.3 million decrease in revenues and a $6.4 million increase in operating expenses. In addition, TGGT recorded an impairment charge to the damaged facility of approximately $12.0 million in the second quarter of 2011. The majority of this charge is expected to be offset in the future by insurance proceeds. Despite the reduction in TGGT’s treating capacity and related curtailment of throughput, TGGT’s current throughput is approximately 1.5 Bcf per day, approximately the same level as prior to the incident.

As a result of the treating facility incident, we recognized an estimated $7.8 million negative impact in our equity method income for the second quarter of 2011, and anticipate an additional $4.8 million negative impact for the remainder of the year.

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 $19.5 million and $36.8 million for the three and six months ended June 30, 2011, respectively, compared to $12.9 million and $24.0 million for the three and six months ended June, 2010, respectively. The overall increase in gathering and transportation expenses is a result of increased volumes and new firm transportation agreements in the Haynesville area, which commenced in February 2010, along with the fees charged by TGGT. As a result of the aforementioned TGGT incident discussed inMidstream operations, we anticipate a slight increase in our per unit gathering rates for the remainder of 2011.

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 Mmcf 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 June 30, 2011 decreased by $2.1 million, or 24.3%, over the same period in 2010. For the six months ended June 30, 2011, production and ad valorem taxes decreased to $12.0 million from $16.4 million for the six months ended June 30, 2010, or 26.5%. On a percentage of

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revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 3.1% of gross oil and natural gas sales for the three months ended June 30, 2011 compared with 7.2% during the same period in the prior year, and 3.3% of gross oil and natural gas sales for the six months ended June 30, 2011 compared with 6.6% during the same period in the prior year.

The decrease in the percentage of revenue basis for the three and six months ended June 30, 2011 compared to the same periods 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, particularly Texas, production taxes are based on a fixed percentage of gross value of products sold. We are presently increasing our drilling operations in the Shelby Trough area of East Texas/North Louisiana. While severance tax holidays are available in Texas, as our production increases, our realized severance and ad valorem tax rates may become more sensitive to prices.

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 July 2011, the state of Louisiana elected not to change the rate from the 2010 rate. In addition, the Commonwealth of Pennsylvania continues to contemplate an impact fee in lieu of a severance tax. While the budget currently being debated does not include an impact fee, the legislature intends to revisit the issue in the fall of 2011. Whether this legislation will be included in future discussion, and ultimately approved by the Pennsylvania House and the Governor of Pennsylvania, is unknown at this time.

Overall, our severance and ad valorem tax rates were $0.14 per Mcfe for the three months ended June 30, 2011 compared with $0.32 per Mcfe for the three months ended June 30, 2010 and $0.15 per Mcfe for the six months ended June 30, 2011, compared with $0.33 per Mcfe for the six months ended June 30, 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 June 30,
	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	$	169,795		40,827	$	4,096		2.4	%	$	0.10	$	90,354		22,097	$	6,666		7.4	%	$	0.30
Appalachia		13,029		2,866		418		3.2	%		0.15		11,912		2,669		506		4.2	%		0.19
Permian and other		24,004		1,842		1,934		8.1	%		1.05		16,078		1,781		1,349		8.4	%		0.76
Total	$	206,828		45,535	$	6,448		3.1	%		0.14	$	118,344		26,547	$	8,521		7.2	%		0.32

	Six months ended June 30,
	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	$	295,001		72,772	$	7,730		2.6	%	$	0.11	$	184,349		40,850	$	12,164		6.6	%	$	0.30
Appalachia		25,666		5,646		707		2.8	%		0.13		31,266		6,010		1,272		4.1	%		0.21
Permian and other		47,389		3,800		3,610		7.6	%		0.95		33,723		3,478		2,950		8.7	%		0.85
Total	$	368,056		82,218	$	12,047		3.3	%		0.15	$	249,338		50,338	$	16,386		6.6	%		0.33

Depletion

Our depletion expense for the three and six months ended June 30, 2011 increased by $39.6 million and $68.9 million, or 96.2% and 91.6%, respectively, from the same periods in 2010. The increase is primarily the 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 and six months ended June 30, 2011 were $1.77 and $1.75, respectively, compared with $1.55 and $1.49, respectively, for the prior year periods.

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Depreciation and amortization

Our depreciation and amortization costs for the three and six months ended June 30, 2011 increased by $0.5 million and $0.3 million, or 12.0% and 3.5% from the same periods in 2010.

Accretion of discount on asset retirement obligations for the three and six months ended June 30, 2011 decreased by $0.1 million and $0.3 million, or 6.8% and 14.4%, respectively, from the same periods in 2010. The decreases are due to the formation of the Appalachia JV, partially offset by future plugging liabilities in connection with our 2011 acquisitions and well additions.

General and administrative

The following table presents our general and administrative expenses for the three and six months ended June 30, 2011 and 2010:

	Three months ended June 30,						Quarter to quarter  change			Six months ended June 30,						Period to period  change
(in thousands, except per unit rate)	2011			2010						2011			2010
General and administrative costs:
Gross general and administrative expense	$	31,635		$	32,525		$	(890	)	$	63,483		$	65,678		$	(2,195	)
Operator overhead reimbursements		(4,568	)		(4,102	)		(466	)		(8,886	)		(7,872	)		(1,014	)
Capitalized acquisition and development charges		(3,930	)		(2,557	)		(1,373	)		(8,037	)		(5,521	)		(2,516	)
General and administrative expense	$	23,137		$	25,866		$	(2,729	)	$	46,560		$	52,285		$	(5,725	)
General and administrative expense per Mcfe	$	0.51		$	0.97		$	(0.46	)	$	0.57		$	1.04		$	(0.47	)

Our general and administrative costs for the three months ended June 30, 2011 were $23.1 million, or $0.51 per Mcfe, compared to $25.8 million, or $0.97 per Mcfe, for the same period in 2010, a decrease of $2.7 million, or 10.6%. Our general and administrative costs for the six months ended June 30, 2011 were $46.6 million, or $0.57 per Mcfe, compared to $52.3 million, or $1.04 per Mcfe, for the same period in 2010, a decrease of $5.7 million, or 10.9%.

Significant components of the net decrease for the three and six months ended June 30, 2011 include the following items:

• decreased legal costs of $1.5 million for the six months ended June 30, 2011 due to a decrease in various claims and settlements;

• decreased travel costs of $0.5 million for the three months ended June 30, 2011 due to the prior year formation of the Appalachia JV;

• decreased relocation costs of $0.8 million for the three months ended June 30, 2011 due to the employees relocated and hired for the Appalachia JV;

• decreased share-based compensation costs of $1.2 million and $2.9 million for the three and six months ended June 30, 2011, respectively, due primarily to a reduction in options granted in 2010 and reduced option grants in 2011 attributable to the special committee’s review of strategic alternatives;

• increased capitalized charges of $1.3 million and $2.5 million for the three and six months ended June 30, 2011, respectively, primarily related to increased personnel;

• increased operator overhead recoveries of $0.5 million and $1.0 million for the three and six months ended June 30, 2011, respectively, due to increased drilling in our shale plays; and

• increased recoveries of technical and administrative service costs of $2.0 million and $3.1 million from our service agreements with BG Group for the three and six months ended June 30, 2011, respectively.

The above decreases are partially offset by personnel charges of $3.9 million and $5.7 million for the three and six months ended June 30, 2011, due primarily to technical employees hired to develop our shale resource asset base.

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Interest expense

Our interest expense decreased approximately $0.8 million for the three months ended June 30, 2011 and increased approximately $3.4 million for the six months ended June 30, 2011 from the same periods in 2010. The decrease of $0.8 million for the three months ended June 30, 2011 was primarily due to a net increase of $7.2 million of interest on the 2018 Notes and the 2011 Notes offset by increased capitalized interest and write-offs of deferred financing costs. The increase of $3.4 million for the six months ended June 30, 2011 was primarily due to net increases of $14.4 million of interest on the 2018 Notes and the 2011 Notes and an increase of $1.2 million paid in connection with formation of the TGGT Credit Agreement, which were partially offset by increased capitalized interest and write-offs of deferred financing costs.

	Three months ended June 30,						Quarter to quarter change			Six months ended June 30,						Period to period change
(in thousands)	2011			2010						2011			2010
Interest expense:
2011 Notes (1)	$	—		$	7,112		$	(7,112	)	$	—		$	14,239		$	(14,239	)
2018 Notes		14,325			—			14,325			28,645			—			28,645
EXCO Resources Credit Agreement		5,713			3,760			1,953			10,906			4,624			6,282
EXCO Operating Credit Agreement (2)		—			1,441			(1,441	)		—			6,008			(6,008	)
Amortization and write-off of deferred financing costs on EXCO Resources Credit Agreement		1,071			942			129			2,294			1,293			1,001
Amortization of deferred financing costs on EXCO Operating Credit Agreement (2)		—			3,943			(3,943	)		—			4,436			(4,436	)
Amortization of deferred financing costs on 2018 Notes		467			—			467			934			—			934
Interest rate swaps settlements		—			—			—			—			2,063			(2,063	)
Fair market value adjustment on interest rate swaps		—			—			—			—			(2,018	)		2,018
Capitalized interest		(8,008	)		(3,199	)		(4,809	)		(15,748	)		(6,114	)		(9,634	)
Other		111			477			(366	)		1,464			579			885
Total interest expense	$	13,679		$	14,476		$	(797	)	$	28,495		$	25,110		$	3,385

(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 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 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.

	Three months ended June 30,					Quarter to quarter change			Six months ended June 30,						Period to period change
(in thousands)	2011		2010						2011			2010
Derivative financial instrument activities:
Cash settlements on derivative financial instruments, excluding early terminations	$	23,217	$	46,538		$	(23,321	)	$	50,152		$	85,649		$	(35,497	)
Cash settlements on early terminations of derivative financial instruments				—			—			—			37,936			(37,936	)
Non-cash change in fair value of derivative financial instruments		20,056		(45,831	)		65,887			(3,458	)		(23,729	)		20,271
Total derivative financial instrument activities	$	43,273	$	707		$	42,566		$	46,694		$	99,856		$	(53,162	)

The use of derivative financial instruments allows us to limit the impact of volatile price fluctuations associated with oil and natural gas. The following table presents our natural gas prices, before the impact of derivative financial instruments, where average realized prices per Mcfe decreased to $4.48 during the six months ended June 30, 2011 from $4.95 during the six months ended June 30, 2010. The impact of the cash settlements on our derivatives (excluding early terminated contracts in 2010) increased our price to $5.09 per Mcfe for the six months ended June 30, 2011 and increased our price to $6.65 per Mcfe for the six months ended June 30, 2010. During the first quarter of 2010, we terminated certain derivative financial contracts prior to their expiration and received $37.9 million, which further increased our realized price by $0.75 per Mcfe for the six months ended June 30, 2010 to $7.40 per Mcfe.

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	Three months ended June 30,				Quarter to quarter change			Six months ended June 30,				Period to period change
Realized pricing:	2011		2010					2011		2010
Oil per Bbl	$	99.16	$	74.44	$	24.72		$	94.40	$	74.83	$	19.57
Natural gas per Mcf		4.25		4.14		0.11			4.16		4.65		(0.49	)
Natural gas equivalent per Mcfe	$	4.54	$	4.46	$	0.08		$	4.48	$	4.95	$	(0.47	)
Cash settlements on derivatives, excluding early terminations, per Mcfe		0.51		1.75		(1.24	)		0.61		1.70		(1.09	)
Net price per Mcfe, including derivative financial instruments before early terminations	$	5.05	$	6.21	$	(1.16	)	$	5.09	$	6.65	$	(1.56	)
Cash settlements on early terminations of derivative financial instruments, per Mcfe		—		—		—			—		0.75		(0.75	)
Net price per Mcfe, derivative financial instruments	$	5.05	$	6.21	$	(1.16	)	$	5.09	$	7.40	$	(2.31	)

Our total cash settlements for the three months ended June 30, 2011 increased revenue by $23.2 million, or $0.51 per Mcfe, compared to $46.5 million, or $1.75 per Mcfe, for the same period in 2010. Our total cash settlements for the six months ended June 30, 2011, including derivatives settled early, increased revenue by $50.2 million, or $0.61 per Mcfe, compared to cash settlements increasing revenues by $123.6 million, or $2.45 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 and six months ended June 30, 2011 resulted in gains of $20.1 million and losses of $3.5 million, respectively, compared to losses of $45.8 million and $23.7 million, respectively, 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 as part of our overall acquisition and financing strategy to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure.

Income taxes

Our effective income tax rate for the three and six months ended June 30, 2011 was zero and for the three and six months ended June 30, 2010 was an expense of 0.8% and 0.7%, respectively, 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 June 30, 2011 is approximately $345.9 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 and six months ended June 30, 2011 and 2010 would have been approximately 39.9% and 39.9%, respectively and 40.6% and 40.5%, respectively.

Our liquidity, capital resources and capital commitments

Overview

Our primary sources of capital resources and liquidity are internally generated cash flows from operations, borrowing capacity under the EXCO Resources Credit Agreement, dispositions of non-strategic assets and issuances of equity and debt securities when capital 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 continue 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 currently believe that our increased production levels coupled with our available borrowing base under the EXCO Resources Credit Agreement will provide sufficient capital to execute our development plans over the next six months. Continued volatility in natural gas prices may impact our development plans. If natural gas prices decline, we may have to curtail some of our development plans.

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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;

• continuation of low natural gas prices;

• shut-in production and decreased revenues from TGGT operations arising from the May 2011 plant incident;

• 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.

We expect to draw on the EXCO Resources Credit Agreement or seek other sources of capital to fund our operations, as required. 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 forecast for 2011 totals $997.0 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 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. The East Texas/North Louisiana Carry was fully utilized during the first quarter of 2011. As of June 30, 2011, approximately $98.1 million of the Appalachia Carry remained unused.

The following table presents capital expenditures for the first six months of 2011 and the capital budget for the remainder of 2011, exclusive of acquisitions, which are not budgeted. The remaining budget for 2011 reflects favorable development capital expenditure impacts in our Appalachia region arising from the Appalachia Carry.

	Six months ended June 30,		July - December forecast		Full year forecast
(dollars in thousands)	2011		2011		2011
Capital expenditures:
Development capital expenditures	$	439,213	$	431,678	$	870,891
Lease purchases(1)		24,626		13,760		38,386
Seismic		5,426		7,512		12,938
Water pipelines and gas gathering		2,084		7,701		9,785
Corporate and other		34,700		30,300		65,000
Total capital expenditures	$	506,049	$	490,951	$	997,000

(1) Net of acreage reimbursements from BG Group totaling $20.7 million in the first half of 2011, and $4.4 million of future reimbursement.

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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. On July 14, 2011, we settled post-closing items which resulted in a final purchase price of $454.4 million ($227.2 million net 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. As of July 27, 2011, the outstanding balance of the TGGT Credit Agreement was $367.1 million.

On March 1, 2011, we jointly closed the purchase of additional prospective Marcellus shale acreage with BG Group, which also included certain shallow production primarily in Jefferson and Clarion counties in Pennsylvania for $82.0 million ($41.0 million net to us).

On April 1, 2011, we entered into the Third Amendment to the EXCO Resources Credit Agreement, resulting in a 50% 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 a $225.2 million acquisition of land, mineral interests and other assets in DeSoto Parish, Louisiana. BG Group elected to participate in the acquisition of its 50% share in accordance with the East Texas/North Louisiana JV. On May 12, 2011, we sold 50% of our membership interests in the LLCs holding the land, mineral interests and other assets in DeSoto Parish, Louisiana to BG Group and received cash proceeds of approximately $112.6 million.

On May 28, 2011, an incident occurred at a TGGT amine treating facility which resulted in the immediate shut-down of two treating facilities. While TGGT has an ongoing investigation into causes of the incident, they have recorded a $12.0 million impairment ($6.0 million net to us) in the second quarter of 2011. This impairment, along with the net impact to their income, caused an estimated $7.8 million negative impact in our equity method income for the second quarter of 2011. The majority of this impairment charge is expected to be offset in the future by insurance recovery. TGGT has ordered temporary treating units and expects resumption of its treating capacity during the third quarter of 2011, with total resumption of treating facilities during the fourth quarter of 2011. We incurred approximately 23 Mmcfe per day of curtailed net volumes in the second quarter of 2011 as a result of this incident.

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. In addition, recent financial reform legislation and proposals to significantly reduce or eliminate income tax incentives available to our industry may negatively affect the capital and credit markets. Although weakness in natural gas prices has continued, 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.

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The following table presents our liquidity and borrowing availability as of June 30, 2011 and July 27, 2011.

(in thousands)	June 30, 2011		July 27, 2011
Cash (1)	$	214,401	$	138,131
Borrowings under the EXCO Resources Credit Agreement		851,500		851,500
2018 Notes (2)		750,000		750,000
Total debt		1,601,500		1,601,500
Net debt	$	1,387,099	$	1,463,369
Consolidated borrowing base	$	1,500,000	$	1,500,000
Total of unused borrowing base (3)	$	638,973	$	638,973
Unused borrowing base plus cash (1) (3)	$	853,374	$	777,104

(1) Includes restricted cash of $149.2 million at June 30, 2011 and $106.2 million at July 27, 2011.

(2) Excludes unamortized bond premium of $10.2 million at June 30, 2011 and $10.1 million at July 27, 2011.

(3) Net of $9.5 million in letters of credit at June 30, 2011 and July 27, 2011.

Historical sources and uses of funds

The following table reflects net increases and decreases in cash for the six months ended June 30, 2011 and 2010.

	Six months ended June 30,
(amounts in thousands)	2011			2010
Cash flows provided by operating activities	$	228,033		$	181,853
Cash flows provided by (used in) investing activities		(197,185	)		139,268
Cash flows provided by (used in) financing activities		(9,891	)		(291,501	)
Net decrease in cash	$	20,957		$	29,620

Our primary sources of cash in the first six months 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, receipt of $125.0 million in return of capital distributions from TGGT and receipt of approximately $112.6 million from BG Group representing reimbursement for their 50% interest in the Haynesville Shale Acquisition.

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 six months ended June 30, 2011 was $228.0 million compared with $181.9 million for the six months ended June 30, 2010. The 25.4% increase in the current year is due primarily to increases in our oil and natural gas producing operating margins compared with the 2010 period, offset by reductions in cash settlements on our derivatives and higher interest costs. As of July 27, 2011, our cash and cash equivalent balance was $138.1 million and our restricted cash account, which is principally used for Haynesville/Bossier shale development operations, was $106.2 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

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primarily with borrowings under the EXCO Resources Credit Agreement. We also receive reimbursements from BG Group on these acquisitions as they elect 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.

In the six month period ended June 30, 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 receipts from BG Group of $229.7 million and $112.6 million, respectively, for its 50% share of the Chief Transaction and the Haynesville Shale Acquisition. We also received cash proceeds of $14.1 million in the second quarter in connection with the sale of certain non-shale producing oil and natural gas properties in East Texas. These inflows were offset by ongoing drilling and development expenditures and the Appalachia Transaction.

Cash flows from financing activities

During the six months ended June 30, 2011, we had borrowings of $380.0 million under the EXCO Resources Credit Agreement in connection with acquisitions in East Texas/North Louisiana and in Appalachia referred to above and repaid $377.5 million of borrowings with funds received from BG Group to reimburse us for its share of the acquisitions and $125.0 million return of capital distribution from TGGT.

EXCO Resources Credit Agreement and long-term debt

As of July 27, 2011, we had total debt outstanding of approximately $1.6 billion, consisting of borrowings under the EXCO Resources Credit Agreement of $851.5 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

The EXCO Resources Credit Agreement, as amended, had a borrowing base of $1.5 billion and outstanding indebtedness of $851.5 million as of July 27, 2011. 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 by 50% 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.

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As of June 30, 2011, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, as amended, which requires that we:

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

• not permit our ratio of consolidated funded indebtedness 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.

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 the 2011 Notes in accordance with the indenture to fully redeem all of the $444.7 million in outstanding 2011 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 June 30, 2011, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at June 30, 2011 was $10.2 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $750.0 million on June 30, 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.

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The foregoing description is not complete and is qualified in its entirety by the indenture governing the 2018 Notes.

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 July 27, 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. On July 8, 2011, the special committee of our Board of Directors terminated their strategic review process. Reinstatement of the stock repurchase program is currently being evaluated.

Derivative financial instruments

We use oil and natural gas derivatives and financial risk management instruments to manage our exposure to commodity price and interest rate fluctuations. We do not designate these instruments as hedging instruments for financial accounting purposes and, accordingly, we recognize the change in the respective instruments’ fair value currently in earnings, as a gain or loss on oil and natural gas derivatives and interest expense on financial risk management instruments.

Recent financial reform legislation has addressed derivative financial instruments, including the possibility of requiring the posting of cash collateral for certain derivative parties. The definitions and specific requirements of this legislation are yet to be defined and we cannot presently quantify the impact to us, if any.

Oil and natural gas derivatives

Our production is generally sold at prevailing market prices. However, we periodically enter into oil and natural gas derivative contracts for a portion of our production when market conditions are deemed favorable and oil and natural gas prices exceed our minimum internal price targets.

Our objective in entering into oil and natural gas derivative contracts is to mitigate the impact of price fluctuations and achieve a more predictable cash flow associated with our operations. These transactions limit our exposure to declines in prices, but also limit the benefits we would realize if oil and natural gas prices increase. As of June 30, 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:
Q3 2011		30,820	$	5.17		138	$	111.32
Q4 2011		30,820		5.17		138		111.32
2012		78,690		5.29		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.

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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)		—		—		851,500		—		851,500
Firm transportation services(3)		82,822		186,139		178,541		429,204		876,706
Other fixed commitments(4)		111,933		124,992		20,297		5,884		263,106
Drilling contracts		104,050		61,107		24		—		165,181
Operating leases		7,510		13,986		7,943		560		29,999
Total contractual obligations	$	306,315	$	386,224	$	1,058,305	$	1,185,648	$	2,936,492

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

(2) The EXCO Resources Credit Agreement, as amended, matures on April 1, 2016.

(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.

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.

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The following table sets forth our oil and natural gas derivative financial instruments measured at fair value as of June 30, 2011.

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at June 30, 2011
Natural gas:
Swaps:
Remainder of 2011		61,640	$	5.17	$	42,664
2012		78,690		5.29		35,527
2013		5,475		5.99		4,475
Total natural gas		145,805				82,666
Oil:
Swaps:
Remainder of 2011		276		111.32		3,971
2012		275		95.70		(1,172	)
Total oil		551				2,799
Total oil and natural gas derivatives					$	85,465

At June 30, 2011, the average forward NYMEX oil prices per Bbl for the remainder of 2011 and for 2012 were $96.90 and $100.04, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2011 and for 2012 were $4.50 and $4.84, 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 June 30, 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 276 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 276 Mbbls. For example, for a hedged volume of 276 Mbbls, if the settlement price is $112.32 per Bbl then other income would decrease by $0.3 million. Conversely, if the settlement price is $110.32 per Bbl, other income would increase by $0.3 million.

Interest rate risk

At June 30, 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 June 30, 2011, we had approximately $851.5 million in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% change in interest rates based on the variable borrowings as of June 30, 2011 would result in an increase or decrease in our interest costs of $8.5 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

Item 4. Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, management has evaluated, under the supervision and with the participation of our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act), as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer have concluded that EXCO’s disclosure controls and procedures were effective as of June 30, 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.

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Changes in internal control over financial reporting. There were no changes in EXCO’s internal control over financial reporting that occurred during the fiscal quarter ended June 30, 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. The state court shareholder class action lawsuit and the state court derivative action lawsuit were nonsuited by the plaintiffs on July 14, 2011 and July 29, 2011, respectively.

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 June 30, 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)
April 1 - April 30, 2011		0	$	0.00		0	$	192.5 million
May 1 - May 31, 2011		0	$	0.00		0	$	192.5 million
June 1 - June 30, 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. On July 8, 2011, the special committee of our board of directors terminated their strategic alternative review process. Reinstatement of the stock purchase plan is currently being evaluated.

Item 5. Other Information

On August 1, 2011, EXCO received a subpoenaduces tecum from the staff of the SEC requesting certain information from January 1, 2008 through the present pertaining to our proved developed producing shale gas wells and reserve estimates. The SEC stated that this investigation is a fact-finding inquiry. We understand that a number of other shale gas producers have received similar subpoenas from the SEC.

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: August 3, 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.

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Exhibit Number	Description of Exhibits
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 as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on May 4, 2011 and incorporated by reference herein.
2.16	Seventh Amendment to Membership Interest Transfer Agreement, dated as of June 16, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed herewith.
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.

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Exhibit Number	Description of Exhibits
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.
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.

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Exhibit Number	Description of Exhibits
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.
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.

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Exhibit Number	Description of Exhibits
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.
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 as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on May 4, 2011 and incorporated by reference herein.
10.36	Seventh Amendment to Membership Interest Transfer Agreement, dated as of June 16, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed herewith as Exhibit 2.16.
10.37	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.
10.38	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.
10.39	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.
10.40	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.
10.41	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.

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Exhibit Number	Description of Exhibits
10.42	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.
10.43	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.
10.44	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.
10.45	Form of Director Indemnification Agreement, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 10, 2010 and filed on November 12, 2010 and incorporated by reference herein.
10.46	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.
10.47	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.

62