Exco Resources (EXCO) 10-Q 2011 Q3 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 September 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 October 27, 2011 was 214,803,974.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at September 30, 2011 and December 31, 2010	3
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010	5
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010	6
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 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
Item 1.	Legal Proceedings	53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 5.	Other Information	54
Item 6.	Exhibits	55
	Signatures	55

2

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	September 30, 2011			December 31, 2010
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	56,418		$	44,229
Restricted cash		117,339			161,717
Accounts receivable, net:
Oil and natural gas		112,309			80,740
Joint interest		146,839			104,358
Interest and other		31,668			35,594
Inventory		8,535			7,876
Derivative financial instruments		114,034			73,176
Other		23,023			12,770
Total current assets		610,165			520,460
Equity investments		287,979			379,001
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		747,131			599,409
Proved developed and undeveloped oil and natural gas properties		3,342,961			2,370,962
Accumulated depletion		(1,552,174	)		(1,312,216	)
Oil and natural gas properties, net		2,537,918			1,658,155
Gas gathering assets		135,635			157,929
Accumulated depreciation and amortization		(27,444	)		(24,772	)
Gas gathering assets, net		108,191			133,157
Office, field, and other equipment, net		44,274			43,149
Deferred financing costs, net		31,518			30,704
Derivative financial instruments		23,356			23,722
Goodwill		218,256			218,256
Deposits on acquisitions		0			464,151
Other assets		7,848			6,665
Total assets	$	3,869,505		$	3,477,420

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	September 30, 2011			December 31, 2010
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	173,196		$	152,999
Revenues and royalties payable		187,170			108,830
Accrued interest payable		3,855			18,983
Current portion of asset retirement obligations		1,279			900
Income taxes payable		0			211
Derivative financial instruments		0			3,775
Total current liabilities		365,500			285,698
Long-term debt		1,712,555			1,588,269
Deferred income taxes		0			0
Derivative financial instruments		578			4,200
Asset retirement obligations and other long-term liabilities		63,073			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; 215,310,953 shares issued and 214,771,732 shares outstanding at September 30, 2011; 213,736,266 shares issued and 213,197,045 shares outstanding at December 31, 2010		215			214
Additional paid-in capital		3,175,184			3,151,513
Accumulated deficit		(1,440,121	)		(1,603,696	)
Treasury stock, at cost; 539,221 shares at September 30, 2011 and December 31, 2010		(7,479	)		(7,479	)
Total shareholders’ equity		1,727,799			1,540,552
Total liabilities and shareholders’ equity	$	3,869,505		$	3,477,420

See accompanying notes.

4

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
(in thousands, except per share data)	2011			2010			2011			2010
Revenues:
Oil and natural gas	$	207,274		$	130,990		$	575,330		$	380,328
Costs and expenses:
Oil and natural gas operating costs		21,101			22,125			60,843			63,821
Production and ad valorem taxes		6,653			3,015			18,700			19,401
Gathering and transportation		22,279			11,561			59,069			35,547
Depreciation, depletion and amortization		100,491			53,687			253,833			137,844
Accretion of discount on asset retirement obligations		938			830			2,728			2,920
General and administrative		29,875			24,034			76,435			76,319
(Gain) loss on divestitures and other operating items		21,045			6,257			25,171			(569,096	)
Total costs and expenses		202,382			121,509			496,779			(233,244	)
Operating income		4,892			9,481			78,551			613,572
Other income (expense):
Interest expense		(15,090	)		(8,440	)		(43,585	)		(33,550	)
Gain on derivative financial instruments		84,284			56,209			130,978			156,065
Other income		193			67			555			184
Equity income		10,666			6,675			22,749			12,054
Total other income (expense)		80,053			54,511			110,697			134,753
Income before income taxes		84,945			63,992			189,248			748,325
Income tax expense (benefit)		0			(904	)		0			3,548
Net income	$	84,945		$	64,896		$	189,248		$	744,777
Earnings per common share:
Basic
Net income	$	0.40		$	0.31		$	0.89		$	3.51
Weighted average common shares outstanding		214,068			212,480			213,831			212,356
Diluted
Net income	$	0.39		$	0.30		$	0.87		$	3.45
Weighted average common and common equivalent shares outstanding		216,314			214,922			217,167			215,627

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine months ended September 30,
(in thousands)	2011			2010
Operating Activities:
Net income	$	189,248		$	744,777
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		253,833			137,844
Share-based compensation		7,537			10,868
Accretion of discount on asset retirement obligations		2,728			2,920
Gain on divestitures		(1,071	)		(574,750	)
Impairment loss on long-lived asset		6,800			0
Income from equity investments		(22,749	)		(12,054	)
Non-cash change in fair value of derivatives		(47,888	)		8,577
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		6,318			3,077
Effect of changes in:
Accounts receivable		(82,803	)		(89,298	)
Other current assets		(6,397	)		(4,579	)
Accounts payable and other current liabilities		49,778			47,707
Net cash provided by operating activities		355,334			275,996
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(754,493	)		(392,370	)
Property acquisitions		(737,357	)		(495,708	)
Proceeds from disposition of property and equipment		428,332			995,573
Investment in equity investments		(13,969	)		(100,000	)
Return of investment in equity investments		125,000			0
Restricted cash		44,378			(41,340	)
Advances (to) from Appalachia JV		3,306			(10,318	)
Deposit on pending acquisitions		464,151			0
Other		(5,750	)		0
Net cash used in investing activities		(446,402	)		(44,163	)
Financing Activities:
Borrowings under credit agreements		521,000			1,402,399
Repayments under credit agreements		(397,500	)		(1,895,563	)
Proceeds from issuance of 2018 Notes		0			738,975
Repayment of 2011 Notes		0			(444,720	)
Proceeds from issuance of common stock		11,776			9,776
Payment of common stock dividends		(25,673	)		(21,238	)
Payments for common shares repurchased		0			(7,479	)
Settlements of derivative financial instruments with a financing element		—			(907	)
Deferred financing costs and other		(6,346	)		(30,359	)
Net cash provided by (used in) financing activities		103,257			(249,116	)
Net increase (decrease) in cash		12,189			(17,283	)
Cash at beginning of period		44,229			68,407
Cash at end of period	$	56,418		$	51,124
Supplemental Cash Flow Information:
Cash interest payments	$	70,758		$	52,424
Income tax payments	$	1,458		$	5,460
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	4,309		$	3,537
Capitalized interest	$	23,155		$	12,709
Issuance of common stock for director services	$	50		$	42

See accompanying notes.

6

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Common Stock				Treasury Stock						Additional paid-in capital		Retained earnings (deficit)			Total shareholders’ equity
(in thousands )	Shares		Amount		Shares			Amount
Balance at December 31, 2009		211,905	$	212		0		$	0		$	3,105,238	$	(2,245,862	)	$	859,588
Issuance of common stock		814		1								9,817					9,818
Share-based compensation												14,405					14,405
Common stock dividends														(21,238	)		(21,238	)
Treasury stock						(539	)		(7,479	)							(7,479	)
Net income														744,777			744,777
Balance at September 30, 2010		212,719	$	213		(539	)	$	(7,479	)	$	3,129,460	$	(1,522,323	)	$	1,599,871
Balance at December 31, 2010		213,736	$	214		(539	)	$	(7,479	)	$	3,151,513	$	(1,603,696	)	$	1,540,552
Issuance of common stock		908		1								11,825					11,826
Share-based compensation												11,846					11,846
Restricted stock issued, net of cancellations		667		0								0					0
Common stock dividends														(25,673	)		(25,673	)
Net income														189,248			189,248
Balance at September 30, 2011		215,311	$	215		(539	)	$	(7,479	)	$	3,175,184	$	(1,440,121	)	$	1,727,799

See accompanying notes.

7

EXO 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 are primarily 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 the following 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 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 September 30, 2011, the remaining balance of the Appalachia Carry was approximately $78.8 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 primarily 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.

The accompanying Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010, the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010, the Condensed Consolidated Statements of Cash Flows and the Condensed Consolidated Statements of Changes in Shareholders’ Equity for the nine months ended September 30, 2011 and 2010 are for EXCO and its subsidiaries. The condensed consolidated financial statements and

8

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 September 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 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. During the third quarter of 2011 we post closed on the Chief Transaction for a final purchase price of $454.4 million ($227.2 million net to us), including all post-closing title adjustments and other customary post-closing purchase price adjustments.

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 and increase in borrowing base

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.

9

TGGT incident

In the second quarter of 2011 an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana resulting in an immediate shut-down of the facility. As a precautionary measure, TGGT also shut down another amine treating facility located in DeSoto Parish with similar specifications, which was restarted in October 2011. TGGT has ordered temporary treating units and expects to be capable of treating all projected northwest Louisiana throughput volumes by early in the first quarter of 2012 once these temporary treating units are operational. TGGT received an initial insurance reimbursement associated with the incident of approximately $6.2 million ($3.1 million net to us) during the third quarter 2011. TGGT expects to have the damaged facility re-commissioned early in 2012.

Former 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. 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. On July 8, 2011, after consultation with its 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 17. Former acquisition proposal” for further information regarding the proposal.

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. 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.

On September 15, 2011 the FASB issued ASU No. 2011-08, Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment, or ASU 2011-08. This ASU allows both public and nonpublic entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity no longer would be required to calculate the fair value of a reporting unit unless the entity determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The ASU, which allows early adoption, will be effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We are presently assessing the impacts of ASU 2011-08.

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.

10

5. Asset retirement obligations

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

(in thousands)
Asset retirement obligation at January 1, 2011	$	50,292
Activity during the nine months ended September 30, 2011:
Adjustment to liability due to acquisitions		1,684
Liabilities incurred during the period		3,369
Liabilities settled during the period		(115	)
Adjustment to liability due to property sales		(982	)
Accretion of discount		2,728
Asset retirement obligations at September 30, 2011		56,976
Less current portion		(1,279	)
Long-term portion	$	55,697

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

6. Oil and natural gas properties and gas gathering assets

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 $747.1 million and $599.4 million as of September 30, 2011 and December 31, 2010, respectively, and are not subject to depletion. The increase in our unproved properties between December 31, 2010 and September 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.

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

11

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 September 30, 2011, the trailing twelve month reference price was $94.50 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma and $4.16 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.

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.

Gas gathering assets

During the third quarter of 2011, we placed certain treating facilities in our Vernon Field for sale and recognized a $6.8 million impairment to write the book values down to an estimated net selling price. Late in September 2011, we sold the facilities.

7. Contingencies

In the ordinary course of business, we are periodically a party to lawsuits. From time to time, natural gas producers, including EXCO, have been named in various lawsuits alleging underpayment of royalties in connection with natural gas and NGLs produced and sold. During the quarter, we reassessed our estimated exposure based on new information presented and as a result increased our estimated reserve.

8. 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 nine months ended September 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 nine months ended September 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 8,078,427 and 6,603,877 antidilutive common stock equivalents from the three months ended September 30, 2011 and 2010, respectively, computations of diluted earnings per share and 2,918,419 and 4,090,014 antidilutive common stock equivalents from the nine months ended September 30, 2011 and 2010, respectively, computations of diluted earnings per share.

12

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

	Three months ended September 30,				Nine months ended September 30,
(in thousands, except per share amounts)	2011		2010		2011		2010
Basic income per common share:
Net income	$	84,945	$	64,896	$	189,248	$	744,777
Shares:
Weighted average number of common shares outstanding		214,068		212,480		213,831		212,356
Basic income per common share:
Net income per common share	$	0.40	$	0.31	$	0.89	$	3.51
Diluted income per share:
Net income	$	84,945	$	64,896	$	189,248	$	744,777
Shares:
Weighted average number of common shares outstanding		214,068		212,480		213,831		212,356
Dilutive effect of
Stock options		2,246		2,442		3,336		3,271
Restricted Shares		0		—		0		—
Weighted average number of common shares and common stock equivalent shares outstanding		216,314		214,922		217,167		215,627
Diluted income per share:
Net income per common share	$	0.39	$	0.30	$	0.87	$	3.45

9. Share-based compensation

Description of Plan

As of September 30, 2011 and December 31, 2010, there were 1,692,940 and 2,068,375 shares, respectively, available for grant under our 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan. Effective October 6, 2011, our shareholders voted to increase the total shares authorized for issuance under the 2005 Incentive Plan from 23,000,000 to 28,500,000 shares, increasing the number of shares available for grant by 5,500,000, and also voted to increase the amount that each restricted share counts against the total number of shares we have available for grant from 1.17 shares to 2.1 shares.

We have historically only granted options under the 2005 Incentive Plan. However, on August 15, 2011 we granted 689,100 shares of restricted stock to certain employees. The restricted shares vest evenly on each of the next three anniversaries of the date of grant. The holders of these shares have voting rights and upon vesting the right to receive all accrued and unpaid dividends.

Compensation Costs

We account for our stock-based options and awards in accordance with FASB ASC Topic 718 for Compensation – Stock Compensation Topic, or ASC 718. As required by ASC 718, the granting of options and awards to our employees under 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.

Total share-based compensation to be recognized on unvested options and restricted stock awards as of September 30, 2011 is $26.1 million. Of this amount, $17.6 million is related to unvested options and will be recognized over a weighted average period of 1.4 years and $8.5 million is related to unvested restricted stock awards and will be recognized over a weighted average period of 2.9 years.

13

The following is a reconciliation of our share-based compensation expense for the three and nine months ended September 30, 2011 and 2010:

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2011		2010		2011		2010
General and administrative expense	$	2,450	$	2,166	$	7,397	$	10,028
Lease operating expense		0		239		140		840
Total share-based compensation expense		2,450		2,405		7,537		10,868
Share-based compensation capitalized		1,509		1,362		4,309		3,537
Total share-based compensation	$	3,959	$	3,767	$	11,846	$	14,405

Stock Options

During the nine months ended September 30, 2011, options to purchase 101,800 shares of common stock were granted under the 2005 Incentive Plan at prices ranging from $14.55 to $20.78 per share with fair values ranging from $7.77 to $11.62 per share. As part of our fair value calculation, 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. During the nine months ended September 30, 2010, options to purchase 489,600 shares of common stock were granted under the 2005 Incentive Plan at prices ranging from $13.97 to $22.22 per share with fair values ranging from $7.43 to $12.77 per share. The options expire 10 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.

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 nine months ended September 30, 2010, we recognized $0.9 million in additional compensation expense related to the modification of option terms of which $0.7 million 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 $14.70 to $21.23 and the exercise prices of the options accelerated ranged from $7.50 to $24.66.

Restricted Stock

During the nine months ended September 30, 2011, 689,100 restricted shares of common stock were granted under the 2005 Incentive Plan at a price of $14.83, which is equal to the closing price of our stock on the date of grant.

A summary of our restricted stock activity for the period ended September 30, 2011 is as follows:

	Shares			Weighted average grant date fair value per share
Non-vested shares outstanding at December 31, 2010		—			—
Granted		689,100		$	14.83
Vested		0			0
Forfeited		(22,000	)		14.83
Non-vested shares outstanding at September 30, 2011		667,100		$	14.83

10. Derivative financial instruments

Our primary objective in entering into derivative financial instruments is to manage our exposure to commodity price fluctuations, protect our returns on investments and achieve a more predictable cash flow in connection with our operations. These transactions limit exposure to declines in commodity prices, but also limit the benefits we would realize if commodity prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts.

14

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	September 30, 2011			December 31, 2010
Commodity contracts	Derivative financial instruments - Current assets	$	114,034		$	73,176
Commodity contracts	Derivative financial instruments - Long-term assets		23,356			23,722
Commodity contracts	Derivative financial instruments - Current liabilities		0			(3,775	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(578	)		(4,200	)
Net derivatives		$	136,812		$	88,923

The Effect of Derivative Financial Instruments

		Three months ended September 30,				Nine months ended September 30,
(in thousands)	Statement of Operations location	2011		2010		2011		2010
Commodity contracts (1)	Gain on derivative financial instruments	$	84,284	$	56,209	$	130,978	$	156,065
Interest rate contracts (2)	Interest income (expense)		0		0		0		(45	)
Net gain		$	84,284	$	56,209	$	130,978	$	156,020

(1) Included in these amounts are net cash receipts of $32,938 and $83,090 for the three and nine months ended September 30, 2011, respectively, and net cash receipts of $43,075 and $166,660 for the three and nine months ended September 30, 2010, respectively.

(2) Included in these amounts are net cash payments of $0 and $2,063 for the three and nine months ended September 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 September 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, were gains of $51.4 million and $13.1 million for the three months ended September 30, 2011 and 2010, respectively, and gains of $47.9 million and losses of $10.6 million for the nine months ended September 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 nine months ended September 30, 2010. There was no impact for the three and nine months ended September 30, 2011 and for the three months ended September 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 September 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.

15

The following table presents the volume and fair value of our oil and natural gas derivative financial instruments as of September 30, 2011:

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2011
Natural gas:
Swaps:
Remainder of 2011		30,820	$	5.17	$	41,408
2012		80,520		5.27		80,896
2013		5,475		5.99		6,301
Total natural gas		116,815				128,605
Oil:
Swaps:
Remainder of 2011		138		111.32		4,323
2012		275		95.70		3,884
Total oil		413				8,207
Total oil and natural gas derivatives					$	136,812

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 September 30, 2011, the average forward NYMEX oil prices per Bbl for the remainder of 2011 and for 2012 were $79.37 and $81.06 respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2011 and for 2012 were $3.80 and $4.24, respectively.

Our derivative financial instruments used to mitigate price volatility covered approximately 63.7% and 57.6% for the three and nine months ended September 30, 2011, respectively, and approximately 49.6% and 56.2% for the three and nine months ended September 30, 2010, respectively, of our total equivalent Mcfe production.

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

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

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

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

Fair value of derivative financial instruments

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

16

	September 30, 2011
(in thousands)	Level 1		Level 2		Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	136,812	$	—	$	136,812
	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 (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 10. 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 $678.6 million with a carrying amount of $740.1 million as of September 30, 2011. The estimated fair value has been calculated based on market quotes.

17

12. Long-term debt

Our total debt is summarized as follows:

(in thousands)	September 30, 2011			December 31, 2010
EXCO Resources Credit Agreement	$	972,500		$	849,000
2018 Notes		750,000			750,000
Unamortized discount on 2018 Notes		(9,945	)		(10,731	)
Total debt	$	1,712,555		$	1,588,269

As of September 30, 2011, we had total debt outstanding of approximately $1.7 billion consisting of borrowings under the EXCO Resources Credit Agreement of $972.5 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 September 30, 2011, the EXCO Resources Credit Agreement had a borrowing base of $1.5 billion, with $972.5 million of outstanding indebtedness and $518.0 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 EXCO Resources Credit 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 September 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 EXCO Resources Credit Agreement) during the first two years of the forthcoming five-year period, 90% of the forecasted production for any month during the third year of the forthcoming five-year period and 85% of the forecasted production from total Proved Reserves during the fourth and fifth year of the forthcoming five-year period.

The EXCO Resources Credit Agreement sets forth the terms and conditions under which we are permitted to pay a cash dividend on our common stock and provides that we may declare and pay cash dividends on our common stock in an amount not to exceed $50.0 million in any four consecutive fiscal quarters, provided that, as of each payment date and after giving effect to the dividend payment date, (i) no default has occurred and is continuing, (ii) we have at least 10% of our borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes.

As of September 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 EXCO Resources Credit Agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and

• not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) to be greater than 4.0 to 1.0 at the end of any fiscal quarter ending on or after December 31, 2010.

18

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 September 30, 2011, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at September 30, 2011 was $9.9 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $678.6 million on September 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.

13. Dividends

On September 1, 2011, our Board of Directors approved a cash dividend of $0.04 per share for the third quarter of 2011. The total cash dividend of $8.6 million was paid on September 30, 2011 to holders of record on September 15, 2011. Dividends paid in 2011 total $25.7 million as of September 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.

14. Income taxes

Each quarter we evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws and apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial deferred tax assets primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties that are subject to valuation allowances. Also, we have tax net operating losses as a result of our drilling programs. For the three and nine months ended September 30, 2011, we estimate that we have utilized $34.0 million and $75.7 million, respectively, of our accumulated valuation allowance. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $311.9 million as of September 30, 2011. The valuation allowances will continue to be recognized until

19

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.

15. 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 and the recognition of a $12.0 million impairment ($6.0 million net to us) in the second quarter of 2011. During the third quarter of 2011, TGGT collected an initial insurance reimbursement of approximately $6.2 million ($3.1 million net to us) in insurance recoveries related to the damaged facility. The insurance recoveries were mostly offset by losses arising from write-downs of equipment. One of the treating facilities resumed operations in October 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 nine months 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. During the third quarter of 2011, EXCO and BG Group each contributed $3.5 million to the Appalachia Midstream JV to fund their capital budget and operation needs.

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

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

20

(in thousands)	September 30, 2011		December 31, 2010
Assets:
Total current assets	$	173,540	$	120,475
Property and equipment, net		1,060,064		873,228
Other assets		3,929		6,143
Total assets	$	1,237,533	$	999,846
Liabilities and members’ equity:
Total current liabilities	$	141,116	$	145,006
Total long-term debt		432,142		—
Total long-term liabilities		4,386		10,092
Total members’ equity		659,889		844,748
Total liabilities and members’ equity	$	1,237,533	$	999,846

	Three months ended				Nine months ended
(in thousands)	September 30, 2011		September 30, 2010		September 30, 2011		September 30, 2010
Revenues:
Oil and natural gas	$	130	$	69	$	386	$	94
Midstream		64,180		39,133		179,820		114,485
Total revenues		64,310		39,202		180,206		114,579
Costs and expenses:
Oil and natural gas production		17		120		21		162
Midstream operating		29,010		18,916		80,320		69,800
Other expenses		6,979		2,905		35,041		10,483
Depreciation, depletion, and amortization		7,511		4,971		21,022		12,651
Total costs and expenses		43,517		26,912		136,404		93,096
Income before income taxes		20,793		12,290		43,802		21,483
Income tax expense		399		87		1,118		246
Net income	$	20,394	$	12,203	$	42,684	$	21,237
EXCO’s share of equity income before amortization	$	10,197	$	6,102	$	21,342	$	10,619
Amortization of the difference in the historical basis of our contribution		469		573		1,407		1,435
EXCO’s share of equity income after amortization	$	10,666	$	6,675	$	22,749	$	12,054

(in thousands)	September 30, 2011			December 31, 2010
Equity investments	$	287,979		$	379,001
Basis adjustment (1)		45,755			45,755
Cumulative amortization of basis adjustment (2)		(3,789	)		(2,382	)
EXCO’s 50% interest in equity investments	$	329,945		$	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 of $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.

16. 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. Repurchases are 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 September 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

21

of our outstanding common stock. On July 8, 2011, the special committee of our Board of Directors terminated their strategic alternatives review process and on August 5, 2011, our Board of Directors agreed to reinstate the repurchase program.

17. Former 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. 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.

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 was 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 would attach to each share issued thereafter prior to the expiration of the rights. The rights would have become exercisable (subject to customary exceptions) only if a person or group acquired 10% or more of the Company’s common stock (thereby becoming an “acquiring person”) or commenced a tender offer for 10% or more of the Company’s common stock. The plan exempted each holder of 10% or more of the Company’s common stock on the date of the plan’s adoption as long as they did 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 could have, in its sole discretion, also exempted any transaction from triggering the plan. On August 19, 2011, the Board determined to amend the Rights Plan to accelerate the Expiration Date from the close of business on January 24, 2012 to the close of business on September 30, 2011.

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 8, 2011, after consultation with its 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. On August 12, 2011, our board of directors, following the report of the special committee that it had fulfilled its responsibilities, determined that it was appropriate to disband the special committee.

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.

Also, since November 3, 2010, two putative shareholder class actions were filed against the Company and all of the members of our board of directors in state district courts in Dallas County, Texas.

All of the state court proceedings were consolidated into one court and were handled as a consolidated derivative action and a consolidated class action. Separate lead plaintiffs’ counsel were appointed for the consolidated derivative action and the consolidated direct class action. As a result, there were three lawsuits in Texas state and federal courts related to Mr. Miller’s proposal: the consolidated derivative action and consolidated direct class action were pending in state court and one derivative action was pending in federal court. During the third quarter 2011, the plaintiffs in the two state court actions voluntarily nonsuited those cases and the federal court action was dismissed.

22

18. Condensed consolidating financial statements

As of September 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 and for the nine months ended September 30, 2011:

• Our equity method investment in OPCO represented $2.8 million of equity method investments and contributed $0.3 million of equity method losses; and

• Our interests in jointly held entities with BG Group, with the exception of OPCO, represented $285.2 million of equity method investments, or 7.4% of our total assets and contributed $23.0 million of equity method income.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 2010 condensed consolidating financial statements have been restated to reflect the consolidation of the EOC credit agreement into the EXCO Resources Credit Agreement, which occurred on April 30, 2010. The 2018 Notes, which were issued by EXCO Resources, Inc., are jointly and severally guaranteed by some of our subsidiaries (referred to as Guarantor Subsidiaries). Each of the Guarantor Subsidiaries are wholly-owned subsidiaries of Resources (defined below), and the guarantees are unconditional as it relates to the assets of the Guarantor Subsidiaries. For purposes of this footnote, EXCO Resources, Inc. is referred to as Resources to distinguish it from the Guarantor Subsidiaries.

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

• Resources;

• the Guarantor Subsidiaries on a combined basis;

• the Non-Guarantor Subsidiaries;

• elimination entries necessary to consolidate Resources, the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries; and

• EXCO on a consolidated basis.

Investments in subsidiaries are accounted for using the equity method of accounting. The financial information for the Guarantor Subsidiaries and the Non-Guarantor Subsidiaries is presented on a combined basis. The elimination entries primarily eliminate investments in subsidiaries and intercompany balances and transactions.

23

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

September 30, 2011

(in thousands)	Resources			Guarantor subsidiaries			Non-Guarantor subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	79,299		$	(22,881	)	$	0		$	0		$	56,418
Restricted cash		0			117,339			0			0			117,339
Other current assets		133,990			302,418			0			0			436,408
Total current assets		213,289			396,876			0			0			610,165
Equity investment		0			0			287,979			0			287,979
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		25,311			721,820			0			0			747,131
Proved developed and undeveloped oil and natural gas properties		444,887			2,898,074			0			0			3,342,961
Accumulated depletion		(314,659	)		(1,237,515	)		0			0			(1,552,174	)
Oil and natural gas properties, net		155,539			2,382,379			0			0			2,537,918
Gas gathering, office and field equipment, net		28,808			123,657			0			0			152,465
Investments in and advances to affiliates		1,092,098			0			0			(1,092,098	)		0
Deferred financing costs, net		31,518			0			0			0			31,518
Derivative financial instruments		17,229			6,127			0			0			23,356
Goodwill		38,100			180,156			0			0			218,256
Other assets		3			7,845			0			0			7,848
Total assets	$	1,576,584		$	3,097,040		$	287,979		$	(1,092,098	)	$	3,869,505
Liabilities and shareholders’ equity
Current liabilities	$	67,651		$	297,849		$	0		$	0		$	365,500
Long-term debt		1,712,555			0			0			0			1,712,555
Deferred income taxes		0			0			0			0			0
Other liabilities		7,721			55,930			0			0			63,651
Payable to parent		(1,939,142	)		1,945,298			(6,156	)		0			0
Total shareholders’ equity		1,727,799			797,963			294,135			(1,092,098	)		1,727,799
Total liabilities and shareholders’ equity	$	1,576,584		$	3,097,040		$	287,979		$	(1,092,098	)	$	3,869,505

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 September 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	22,725		$	184,549		$	0		$	0		$	207,274
Costs and expenses:
Oil and natural gas production		4,987			22,767			0			0			27,754
Gathering and transportation		1			22,278			0			0			22,279
Depreciation, depletion and amortization		11,609			88,733			149			0			100,491
Accretion of discount on asset retirement obligations		113			825			0			0			938
General and administrative		10,059			19,816			0			0			29,875
Gain (loss) on divestitures and other operating items		15,753			5,568			(276	)		0			21,045
Total costs and expenses		42,522			159,987			(127	)		0			202,382
Operating income (loss)		(19,797	)		24,562			127			0			4,892
Other income (expense):
Interest expense		(15,089	)		(1	)		0			0			(15,090	)
Gain on derivative financial instruments		74,063			10,221			0			0			84,284
Other income (expense)		77			116			0			0			193
Equity income		0			0			10,666			0			10,666
Equity in earnings of subsidiaries		45,691			0			0			(45,691	)		0
Total other income (expense)		104,742			10,336			10,666			(45,691	)		80,053
Income (loss) before income taxes		84,945			34,898			10,793			(45,691	)		84,945
Income tax expense		0			0			0			0			0
Net income (loss)	$	84,945		$	34,898		$	10,793		$	(45,691	)	$	84,945

26

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Oil and natural gas	$	17,025		$	108,362		$	5,603	$	0		$	130,990
Costs and expenses:
Oil and natural gas production		3,833			20,755			552		0			25,140
Gathering and transportation		0			11,254			307		0			11,561
Depreciation, depletion and amortization		8,540			43,071			2,076		0			53,687
Accretion of discount on asset retirement obligations		87			742			1		0			830
General and administrative		6,468			17,566			0		0			24,034
Gain on divestitures and other operating items		5,652			605			0		0			6,257
Total costs and expenses		24,580			93,993			2,936		0			121,509
Operating income (loss)		(7,555	)		14,369			2,667		0			9,481
Other income (expense):
Interest expense		(8,439	)		(1	)		0		0			(8,440	)
Gain on derivative financial instruments		30,427			25,782			0		0			56,209
Other income (expense)		16			51			0		0			67
Equity method income		0			0			6,675		0			6,675
Equity in earnings of subsidiaries		49,543			0			0		(49,543	)		0
Total other income (expense)		71,547			25,832			6,675		(49,543	)		54,511
Income (loss) before income taxes		63,992			40,201			9,342		(49,543	)		63,992
Income tax expense (benefit)		(904	)		0			0		0			(904	)
Net income (loss)	$	64,896		$	40,201		$	9,342	$	(49,543	)	$	64,896

27

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	70,115		$	505,215		$	0		$	0		$	575,330
Costs and expenses:
Oil and natural gas production		14,334			65,209			0			0			79,543
Gathering and transportation		1			59,068			0			0			59,069
Depreciation, depletion and amortization		25,379			227,501			953			0			253,833
Accretion of discount on asset retirement obligations		321			2,407			0			0			2,728
General and administrative		19,375			57,061			(1	)		0			76,435
Gain (loss) on divestitures and other operating items		20,355			6,098			(1,282	)		0			25,171
Total costs and expenses		79,765			417,344			(330	)		0			496,779
Operating income (loss)		(9,650	)		87,871			330			0			78,551
Other income (expense):
Interest expense		(42,326	)		(1,259	)		0			0			(43,585	)
Gain on derivative financial instruments		113,670			17,308			0			0			130,978
Other income (expense)		262			293			0			0			555
Equity method income		0			0			22,749			0			22,749
Equity in earnings of subsidiaries		127,292			0			0			(127,292	)		0
Total other income (expense)		198,898			16,342			22,749			(127,292	)		110,697
Income (loss) before income taxes		189,248			104,213			23,079			(127,292	)		189,248
Income tax expense		0			0			0			0			0
Net income (loss)	$	189,248		$	104,213		$	23,079		$	(127,292	)	$	189,248

28

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Revenues:
Oil and natural gas	$	50,747		$	320,250		$	9,331	$	0		$	380,328
Costs and expenses:
Oil and natural gas production		11,684			70,625			913		0			83,222
Gathering and transportation		0			34,948			599		0			35,547
Depreciation, depletion and amortization		21,387			113,135			3,322		0			137,844
Accretion of discount on asset retirement obligations		255			2,663			2		0			2,920
General and administrative		20,725			55,594			0		0			76,319
Gain (loss) on divestitures and other operating items		7,816			(576,912	)		0		0			(569,096	)
Total costs and expenses		61,867			(299,947	)		4,836		0			(233,244	)
Operating income (loss)		(11,120	)		620,197			4,495		0			613,572
Other income (expense):
Interest expense		(26,814	)		(6,736	)		0		0			(33,550	)
Gain on derivative financial instruments		64,369			91,696			0		0			156,065
Other income (expense)		10,345			(10,161	)		0		0			184
Equity method income		0			0			12,054		0			12,054
Equity in earnings of subsidiaries		711,545			0			0		(711,545	)		0
Total other income (expense)		759,445			74,799			12,054		(711,545	)		134,753
Income (loss) before income taxes		748,325			694,996			16,549		(711,545	)		748,325
Income tax expense		3,548			0			0		0			3,548
Net income (loss)	$	744,777		$	694,996		$	16,549	$	(711,545	)	$	744,777

29

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2011

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	61,069		$	293,094		$	1,171		$	0	$	355,334
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment and property acquisitions		(51,201	)		(1,436,396	)		(4,253	)		0		(1,491,850	)
Proceeds from disposition of property and equipment		3,128			425,204			0			0		428,332
Investment in equity investments		0			(13,969	)		0			0		(13,969	)
Return of investment in equity investments		0			125,000			0			0		125,000
Restricted cash		0			44,378			0			0		44,378
Advances (to) from Appalachia JV		0			3,306			0			0		3,306
Deposit on pending acquisitions		0			464,151			0			0		464,151
Other		0			(5,750	)		0			0		(5,750	)
Advances/investments with affiliates		(113,717	)		110,635			3,082			0		0
Net cash used in investing activities		(161,790	)		(283,441	)		(1,171	)		0		(446,402	)
Financing Activities:
Borrowings under credit agreement		521,000			0			0			0		521,000
Repayments under credit agreement		(397,500	)		0			0			0		(397,500	)
Proceeds from issuance of common stock		11,776			0			0			0		11,776
Payment of common stock dividends		(25,673	)		0			0			0		(25,673	)
Deferred financing costs and other		(6,346	)		0			0			0		(6,346	)
Net cash used in financing activities		103,257			0			0			0		103,257
Net increase (decrease) in cash		2,536			9,653			0			0		12,189
Cash at the beginning of the period		76,763			(32,534	)		0			0		44,229
Cash at end of period	$	79,299		$	(22,881	)	$	0		$	0	$	56,418

30

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Operating Activities:
Net cash provided by (used in) operating activities	$	56,229		$	228,216		$	(8,449	)		0	$	275,996
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(50,366	)		(599,808	)		(237,904	)		0		(888,078	)
Proceeds from dispositions		8,896			986,677			0			0		995,573
Investment in equity investments		0			(100,000	)		0			0		(100,000	)
Restricted cash		0			(41,340	)		0			0		(41,340	)
Advances (to) from Appalachia JV		0			(10,318	)		0			0		(10,318	)
Advances/investments with affiliates		292,494			(538,847	)		246,353			0		0
Net cash provided by (used in) investing activities		251,024			(303,636	)		8,449			0		(44,163	)
Financing Activities:
Borrowings under credit agreements		1,352,437			49,962			0			0		1,402,399
Repayments under credit agreements		(1,870,582	)		(24,981	)		0			0		(1,895,563	)
Proceeds from issuance of 2018 Notes		738,975			0			0			0		738,975
Repayment of 2011 Notes		(444,720	)		0			0			0		(444,720	)
Proceeds from issuance of common stock, net		9,776			0			0			0		9,776
Payment of common stock dividends		(21,238	)		0			0			0		(21,238	)
Payment for common shares repurchased		(7,479	)		0			0			0		(7,479	)
Settlement of derivative financial instruments with a financing element		(907	)		0			0			0		(907	)
Deferred financing costs and other		(30,359	)		0			0			0		(30,359	)
Net cash provided by (used in) financing activities		(274,097	)		24,981			0			0		(249,116	)
Net increase (decrease) in cash		33,156			(50,439	)		0			0		(17,283	)
Cash at beginning of period		47,412			20,995			0			0		68,407
Cash at end of period	$	80,568		$	(29,444	)	$	0		$	0	$	51,124

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.

32

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. During the third quarter of 2011, natural gas prices for near-term months and futures markets experienced declines which may impact our liquidity, results of operations and development plans, particularly in 2012.

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 are primarily 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 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 September 30, 2011, the remaining balance of the Appalachia Carry was approximately $78.8 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 primarily 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 $1.0 million was drawn as of October 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.

Our plans for 2011 are focused on the Haynesville/Bossier and Marcellus shales. Our forecasted capital expenditures, which exclude $32.5 million of BG Group acreage reimbursements, total $1,014.4 million, of which $896.8 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

33

Louisiana JV are expected to total $810.7 million. During the first nine months of 2011, we spent $624.8 million in East Texas/North Louisiana, excluding $22.8 million of BG Group acreage reimbursements, $618.7 million of which was in the area of mutual interest with BG Group, or the East Texas/North Louisiana AMI. In Appalachia, our share of planned capital expenditures for the Appalachia JV are expected to total $67.0 million for 2011, which reflects the benefit of $68.0 million of the Appalachia Carry. During the first nine months of 2011, we spent $43.0 million in Appalachia, net of the Appalachia Carry. As of September 30, 2011, the remaining balance of the Appalachia Carry was approximately $78.8 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.

For the three and nine months ended September 30, 2011, we funded $3.5 million in equity contributions to the Appalachia Midstream JV and we expect to continue to fund equity contributions in the future as it builds infrastructure to support our development activities in Appalachia.

For the nine months ended September 30, 2011, we produced 131.9 Bcfe of oil and natural gas. Of the amount produced, 117.6 Bcfe were produced in our East Texas/North Louisiana area, 8.6 Bcfe were produced in our Appalachia area and 5.7 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. We are presently evaluating our 2012 capital expenditure budgets.

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.

Significant 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. During the third quarter of 2011 we post closed on the Chief Transaction for a final purchase price of $454.4 million ($227.2 million net to us), including all post-closing title adjustments and other customary post-closing purchase price adjustments.

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.

34

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 and increase in borrowing base

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

In the second quarter of 2011 an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana resulting in an immediate shut-down of the facility. As a precautionary measure, TGGT also shut down another amine treating facility located in DeSoto Parish with similar specifications, which was restarted in October 2011. TGGT has ordered temporary treating units and expects to be capable of treating all projected northwest Louisiana throughput volumes by early in the first quarter of 2012 once these temporary treating units are operational. TGGT received an initial insurance reimbursement associated with the incident of approximately $6.2 million ($3.1 million net to us) during the third quarter 2011. TGGT expects to have the damaged facility re-commissioned early in 2012.

Former 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. 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. On July 8, 2011, after consultation with its 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 17. Former acquisition proposal” of the notes to our condensed consolidated financial statements for further information regarding the proposal.

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. 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.

35

On September 15, 2011 the FASB issued ASU No. 2011-08, Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment, or ASU 2011-08. This ASU allow both public and nonpublic entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity no longer would be required to calculate the fair value of a reporting unit unless the entity determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The ASU, which allows early adoption, will be effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We are presently assessing the impacts of ASU 2011-08.

Our results of operations

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

	Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,					Period to period  change
(dollars in thousands, except per unit prices)	2011		2010		2011-2010			2011		2010			2011-2010
Production:
Oil (Mbbls)		182		178		4			553		505			48
Natural gas (Mmcf)		48,576		28,408		20,168			128,568		76,784			51,784
Total production (Mmcfe) (1)		49,668		29,476		20,192			131,886		79,814			52,072
Average daily production (Mmcfe) (1)		540		320		220			483		292			191
Oil and natural gas revenues before derivative financial instrument activities:
Oil	$	15,596	$	12,968	$	2,628		$	50,618	$	37,437		$	13,181
Natural gas		191,678		118,022		73,656			524,712		342,891			181,821
Total oil and natural gas	$	207,274	$	130,990	$	76,284		$	575,330	$	380,328		$	195,002
Oil and natural gas derivative financial instruments:
Cash settlements (payments) on derivative financial instruments	$	32,938	$	43,075	$	(10,137	)	$	83,090	$	166,660		$	(83,570	)
Non-cash change in fair value of derivative financial instruments		51,346		13,134		38,212			47,888		(10,595	)		58,483
Total derivative financial instrument activities	$	84,284	$	56,209	$	28,075		$	130,978	$	156,065		$	(25,087	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	85.69	$	72.85	$	12.84		$	91.53	$	74.13		$	17.40
Natural gas (per Mcf)		3.95		4.15		(0.20	)		4.08		4.47			(0.39	)
Natural gas equivalent (per Mcfe)		4.17		4.44		(0.27	)		4.36		4.77			(0.41	)
Costs and expenses:
Oil and natural gas operating costs (2)	$	21,101	$	22,125	$	(1,024	)	$	60,843	$	63,821		$	(2,978	)
Production and ad valorem taxes		6,653		3,015		3,638			18,700		19,401			(701	)
Gathering and transportation		22,279		11,561		10,718			59,069		35,547			23,522
Depletion		95,949		49,933		46,016			239,956		125,075			114,881
Depreciation and amortization		4,542		3,754		788			13,877		12,769			1,108
General and administrative (3)		29,875		24,034		5,841			76,435		76,319			116
Interest expense		15,090		8,440		6,650			43,585		33,550			10,035
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.42	$	0.75	$	(0.33	)	$	0.46	$	0.80		$	(0.34	)
Production and ad valorem taxes		0.13		0.10		0.03			0.14		0.24			(0.10	)
Gathering and transportation		0.45		0.39		0.06			0.45		0.45			—
Depletion		1.93		1.69		0.24			1.82		1.57			0.25
Depreciation and amortization		0.09		0.13		(0.04	)		0.11		0.16			(0.05	)
General and administrative		0.60		0.82		(0.22	)		0.58		0.96			(0.38	)
Net income	$	84,945	$	64,896	$	20,049		$	189,248	$	744,777		$	(555,529	)
.

(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 $0.0 million and $0.2 million for the three months ended September 30, 2011 and 2010, respectively, and $0.1 million and $0.8 million for the nine months ended September 30, 2011 and 2010, respectively.

(3) Share-based compensation included in general and administrative expenses is $2.4 million and $2.2 million for the three months ended September 30, 2011 and 2010, respectively, and $7.4 million and $10.0 million for the nine months ended September 30, 2011 and 2010, respectively.

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

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

• the Appalachia JV in 2010;

• 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;

36

• 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 and other infrequent costs or asset impairments.

General

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

• the level of domestic production and economic activity;

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

• the availability of imported oil and natural gas;

• actions taken by foreign oil producing nations;

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

• the cost and availability of other competitive fuels;

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

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

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

Accordingly, in light of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we cannot accurately predict the prices or marketability of oil and natural gas from any producing well in which we have or may acquire an interest.

Marketing arrangements

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

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

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

We engage in oil and natural gas production activities in geographic regions where, from time to time, the supply of oil or natural gas available for delivery exceeds the demand. In this situation, companies purchasing oil or natural gas in these areas reduce the amount of oil or natural gas that they purchase from us. If we cannot locate other buyers for our production or for any of our newly discovered oil or natural gas reserves, we may shut-in our oil or natural gas wells for periods of time. If this occurs, we may incur additional payment obligations under our oil and natural gas leases and, under certain circumstances, the oil and natural gas leases might be terminated. 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 September 30, 2011, we reported net income of $84.9 million compared to net income of $64.9 million for the three months ended September 30, 2010. For the nine months ended September 30, 2011, we reported net income of $189.2 million compared to net income of $744.8 million for the nine months ended September 30, 2010.

37

The decrease in net income for the nine months ended September 30, 2011 from the same periods in 2010 is primarily the result of the $574.8 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. Offsetting the impact of this gain, our production volumes have increased significantly during 2011, principally 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 nine month comparison periods. The horizontal wells produce high volumes of natural gas, but have operating expenses comparable to lower-volume conventional 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 production, revenue and average sales prices by major producing areas for the three and nine months ended September 30, 2011 and 2010:

	Three months ended September 30,
	2011						2010						Quarter to quarter change
(dollars in thousands, except per unit rate)	Production (Mmcfe)		Revenue		$/Mcfe		Production (Mmcfe)		Revenue		$/Mcfe		Production (Mmcfe)		Revenue		$/Mcfe
Producing region:
East Texas/North Louisiana		44,830	$	171,625	$	3.83		26,045	$	106,649	$	4.09		18,785	$	64,976		(0.26	)
Appalachia		2,947		12,924		4.39		1,608		7,316		4.55		1,339		5,608		(0.16	)
Permian and other		1,891		22,725		12.02		1,823		17,025		9.34		68		5,700		2.68
Total		49,668	$	207,274		4.17		29,476	$	130,990		4.44		20,192	$	76,284		(0.27	)

	Nine months ended September 30,
	2011						2010						Period to period change
(dollars in thousands, except per unit rate)	Production (Mmcfe)		Revenue		$/Mcfe		Production (Mmcfe)		Revenue		$/Mcfe		Production (Mmcfe)		Revenue		$/Mcfe
Producing region:
East Texas/North Louisiana		117,602	$	466,626	$	3.97		66,895	$	290,998	$	4.35		50,707	$	175,628	$	(0.38	)
Appalachia		8,593		38,590		4.49		7,618		38,582		5.06		975		8		(0.57	)
Permian and other		5,691		70,114		12.32		5,301		50,748		9.57		390		19,366		2.75
Total		131,886	$	575,330		4.36		79,814	$	380,328		4.77		52,072	$	195,002		(0.41	)

Production in our East Texas/North Louisiana region for the three and nine months ended September 30, 2011 increased by 18.8 Bcfe and 50.7 Bcfe, respectively, from the same periods in the prior year. These increases are the result of the continued successful development of our Haynesville shale, which resulted in production increases of 20.9 Bcfe and 56.3 Bcfe for the three and nine months ended September 30, 2011 when compared to the same periods in the prior year. The increase in Haynesville production is partially offset by production declines from the prior year’s comparable periods of 1.1 Bcfe and 3.8 Bcfe in our Vernon Field for the three and nine months ended September 30, 2011, and Cotton Valley production declines of 1.0 Bcfe and 1.8 Bcfe for the three and nine months ended September 30, 2011. The declines in Vernon and Cotton Valley 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 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 September 30, 2011, oil and natural gas revenues were $207.3 million, a 58.2% increase from the oil and natural gas revenues of $131.0 million for the three months ended September 30, 2010. The increase in revenues is primarily a result of the overall increased production in our Haynesville shale operations and an increase in equivalent oil prices, offset by lower natural gas prices. Our average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased from $72.85 per Bbl for the three months ended September 30, 2010 to $85.69 per Bbl for the three months ended September 30, 2011, or 17.6%. Our average natural gas sales price, excluding the impact of derivative financial instruments, was $3.95 per Mcf for the three months ended September 30, 2011 compared with $4.15 per Mcf for the three months ended September 30, 2010, a decrease of 4.8%.

For the nine months ended September 30, 2011, oil and natural gas revenues were $575.3 million, a 51.3% increase from the oil and natural gas revenues of $380.3 million for the nine months ended September 30, 2010. The increase in revenues is primarily a result of the overall increased production in our Haynesville shale 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 $74.13 per Bbl for the nine months ended September 30, 2010 to $91.53 per Bbl for the nine months ended September 30, 2011, or 23.5%. Our average natural gas sales price, excluding the impact of derivative financial instruments, was $4.08 per Mcf for the nine months ended September 30, 2011 compared with $4.47 per Mcf for the nine months ended September 30, 2010, a decrease of 8.7%.

38

The price we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, estimates of oil and natural gas in storage, weather and other seasonal conditions, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Weakness in natural gas prices persist. 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 nine months ended September 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 and cash flows of approximately $4.3 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 $0.2 million, without considering the effects of derivative financial instruments.

In addition, our production volumes are impacted by shut-in volumes of natural gas due to operational requirements associated with fracture stimulation and other operations on near-by horizontal wells, seasonal supply and demand conditions from end users and general maintenance and repairs to our wells. While these shut-in volumes are typically for short periods of time, they may have impacts to our revenues, cash flows and results of operations. We currently expect that approximately 7.5% 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. As a result of this shutdown, we estimate approximately 44.4 Mmcfe per day of curtailed net volumes occurred in the third quarter. One of the facilities that was shut down became operational in October 2011. TGGT expects full restoration of treating capacity early in the first quarter of 2012. TGGT expects the damaged facility to become operational early in 2012.

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three and nine months ended September 30, 2011 were $21.1 million and $60.8 million, respectively, compared with $22.1 million and $63.8 million for the three and nine months ended September 30, 2010, respectively. For the three months ended September 30, 2011, declines in maintenance and service costs in our shallow Cotton Valley wells and Vernon Field are primarily due to various divestitures in 2011 of property and field equipment. In our Appalachia area, commencement of our Marcellus shale horizontal drilling program and expenses attributable to the properties acquired in the Chief Transaction and the Appalachia Transaction and increased activity in Permian due to resumption of our drilling program during 2010. The decrease for the nine month period reflects reductions in Appalachia related to the formation of the Appalachia JV and similar decreases in our Cotton Valley area and Vernon Field as discussed above, offset by increased activity in the Permian Basin due to the resumption of drilling operations during 2010 and continual increased activity in our Haynesville area. 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 September 30, 2011 decreased $0.33 per Mcfe, a reduction of 44.0% from the same period in 2010, with lease operating expenses representing $0.24 per Mcfe of the decrease and workovers and other expense representing $0.09 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, along with slight decreases in both our Vernon Field and Cotton Valley area due to a decline in unit operating costs. The declines in Cotton Valley and the Vernon Field were primarily due to reductions in maintenance and service costs and the 2011 divestitures of properties and field equipment. In addition, there were decreases in workovers in our Vernon Field. While there was an increase in total oil and natural gas operating expenses for the Appalachia region, there was an overall decrease in operating expenses per Mcfe in Appalachia primarily a result of increased production volumes from Marcellus shale wells, which have lower lease operating expense rate per Mcfe than our historical shallow production. These decreases are offset by the Permian region due to increased activity related to resumption of our drilling program in the third quarter of 2010.

39

	Three months ended September 30,
	2011						2010						Quarter to quarter change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	11,284	$	2,326	$	13,610	$	13,026	$	3,755	$	16,781	$	(1,742	)	$	(1,429	)	$	(3,171	)
Appalachia		4,376		—		4,376		2,804		—		2,804		1,572			—			1,572
Permian and other		3,094		21		3,115		2,289		251		2,540		805			(230	)		575
Total	$	18,754	$	2,347	$	21,101	$	18,119	$	4,006	$	22,125	$	635		$	(1,659	)	$	(1,024	)

	Three months ended September 30,
	2011						2010						Quarter to quarter change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	0.25	$	0.05	$	0.30	$	0.50	$	0.14	$	0.64	$	(0.25	)	$	(0.09	)	$	(0.34	)
Appalachia		1.48		—		1.48		1.74		—		1.74		(0.26	)		—			(0.26	)
Permian and other		1.64		0.01		1.65		1.25		0.14		1.39		0.39			(0.13	)		0.26
Operating costs per Mcfe		0.37		0.05		0.42		0.61		0.14		0.75		(0.24	)		(0.09	)		(0.33	)

On a per Mcfe basis, oil and natural gas operating expenses for the nine months ended September 30, 2011 decreased $0.34 per Mcfe, a decrease of 42.5% from the same period in 2010, with lease operating expenses representing $0.29 per Mcfe of the decrease and workovers and other expense representing $0.05 per Mcfe of the decrease. The decrease in operating expenses per Mcfe in East Texas/North Louisiana are primarily a result of increased production in our Haynesville shale, which has a relatively low lease operating rate per Mcfe, and declines in our Vernon Field and Cotton Valley area due to a decline in unit operating costs. 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.

	Nine months ended September 30,
	2011						2010						Period to period change
(in thousands)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	33,684	$	7,348	$	41,032	$	36,171	$	7,930	$	44,101	$	(2,487	)	$	(582	)	$	(3,069	)
Appalachia		10,960		—		10,960		12,063		216		12,279		(1,103	)		(216	)		(1,319	)
Permian and other		8,497		354		8,851		6,758		683		7,441		1,739			(329	)		1,410
Total	$	53,141	$	7,702	$	60,843	$	54,992	$	8,829	$	63,821	$	(1,851	)	$	(1,127	)	$	(2,978	)

	Nine months ended September 30,
	2011						2010						Period to period change
(per Mcfe)	Lease operating expenses		Workovers and other		Total		Lease operating expenses		Workovers and other		Total		Lease operating expenses			Workovers and other			Total
Producing region:
East Texas/North Louisiana	$	0.29	$	0.06	$	0.35	$	0.54	$	0.12	$	0.66	$	(0.25	)	$	(0.06	)	$	(0.31	)
Appalachia		1.28		—		1.28		1.58		0.03		1.61		(0.30	)		(0.03	)		(0.33	)
Permian and other		1.49		0.06		1.55		1.27		0.13		1.40		0.22			(0.07	)		0.15
Operating costs per Mcfe		0.40		0.06		0.46		0.69		0.11		0.80		(0.29	)		(0.05	)		(0.34	)

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.

40

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. Once completed in the first quarter of 2012, this expansion is expected to increase throughput and treating capacity by approximately 500 Mmcf per day.

In the second quarter 2011 an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana resulting in an immediate shut-down of the facility. As a precautionary measure, TGGT also shut down another amine treating facility located in DeSoto Parish with similar specifications, which was restarted in October 2011. TGGT has ordered temporary treating units and expects to be capable of treating all projected northwest Louisiana throughput volumes early in the first quarter of 2012 once these temporary treating units are operational. The estimated third quarter 2011 impact to TGGT resulting from this incident was an $8.7 million net decrease to their operating income, which was due to an estimated $7.0 million reduction in revenue and a $1.7 million increase in operating expenses. TGGT received an initial insurance reimbursement associated with the incident of approximately $6.2 million during the third quarter 2011. TGGT expects to have the damaged facility re-commissioned early in 2012.

As a result of the treating facility incident, we recognized an estimated $4.4 million negative impact in our equity method income for the third quarter of 2011.

The Appalachia Midstream JV has begun installing and operating gathering systems and facilities 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 $22.3 million and $59.1 million for the three and nine months ended September 30, 2011, respectively, compared to $11.6 million and $35.5 million for the three and nine months ended September 30, 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 of gross operated volumes with annual minimum gathering expenses of approximately $95.0 million.

Production and ad valorem taxes

Production and ad valorem taxes for the three months ended September 30, 2011 increased by $3.6 million, or 120.7%, over the same period in 2010. For the nine months ended September 30, 2011, production and ad valorem taxes decreased to $18.7 million from $19.4 million for the nine months ended September 30, 2010, or 3.6%. On a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 3.2% of gross oil and natural gas sales for the three months ended September 30, 2011 compared with 2.3% during the same period in the prior year, and 3.3% of gross oil and natural gas sales for the nine months ended September 30, 2011 compared with 5.1% during the same period in the prior year. In our East Texas/North Louisiana area, we are presently receiving severance tax holidays on certain Haynesville shale wells which reduce the effective rate of these taxes.

41

The increase in the percentage of revenue basis for the three months ended September 30, 2011 compared to the same periods in 2010 is primarily the result of the natural termination of the severance tax holidays on a number of our Haynesville and Bossier shale wells in Louisiana. While our severance tax holidays may be terminating and increasing the rate for the quarter, the overall decrease in the percentage of revenue basis for the nine months ended September 30, 2011 compared to the same periods in 2010, is primarily the result of the increase year over year in receipt of severance tax holidays on our Haynesville and Bossier shale wells in Louisiana, coupled with a decrease in the severance tax rate. 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. In October 2011, the governor of Pennsylvania released his proposal for an impact fee, which would allow counties to enact an ordinance to impose an impact fee on unconventional wells. This proposal, which would limit the fee at $160,000 per well over a ten year period, will be reviewed and debated by the Pennsylvania legislature. Whether this legislation, or a modified version, will ultimately be approved by the Pennsylvania Senate and House is unknown at this time.

Overall, our severance and ad valorem tax rates were $0.13 per Mcfe for the three months ended September 30, 2011 compared with $0.10 per Mcfe for the three months ended September 30, 2010 and $0.14 per Mcfe for the nine months ended September 30, 2011, compared with $0.24 per Mcfe for the nine months ended September 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.

	For the three months ended September 30,
	2011											2010
(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	$	171,625		44,830	$	4,342		2.5	%	$	0.10	$	106,649		26,045	$	1,513		1.4	%	$	0.06
Appalachia		12,924		2,947		439		3.4	%		0.15		7,316		1,608		209		2.9	%		0.13
Permian and other		22,725		1,891		1,872		8.2	%		0.99		17,025		1,823		1,293		7.6	%		0.71
Total	$	207,274		49,668	$	6,653		3.2	%		0.13	$	130,990		29,476	$	3,015		2.3	%		0.10

	For the nine months ended September 30,
	2011											2010
(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	$	466,626		117,602	$	12,072		2.6	%	$	0.10	$	290,998		66,895	$	13,677		4.7	%	$	0.20
Appalachia		38,590		8,593		1,146		3.0	%		0.13		38,582		7,618		1,481		3.8	%		0.19
Permian and other		70,114		5,691		5,482		7.8	%		0.96		50,748		5,301		4,243		8.4	%		0.80
Total	$	575,330		131,886	$	18,700		3.3	%		0.14	$	380,328		79,814	$	19,401		5.1	%		0.24

Depletion

Our depletion expense for the three and nine months ended September 30, 2011 increased by $46.0 million and $114.9 million, or 92.2% and 91.8%, respectively, from the same periods in 2010. The increase is primarily the result of higher production volumes and increased capital expenditures as a result of the 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 nine months ended September 30, 2011 were $1.93 and $1.82, respectively, compared with $1.69 and $1.57, respectively, for the comparable prior year periods.

During the third quarter of 2011, natural gas prices for near term months and forward futures markets declined substantially. These price decreases can have impacts on depletion rates arising from reduced economical recovery of reserves, and reductions or proved undeveloped drilling locations and related Proved Reserve reductions. Our third quarter 2011 trailing twelve month average

42

natural gas reference price was $4.16 per Mmbtu compared with $4.38 per Mmbtu on December 31, 2010. If prices do not increase in the near term, we could experience ceiling test write-downs in future periods.

Depreciation and amortization

Our depreciation and amortization costs for the three and nine months ended September 30, 2011 increased by $0.8 million and $1.1 million, or 21.0% and 8.7%, respectively, from the same periods in 2010.

Accretion of discount on asset retirement obligations for the three months ended September 30, 2011 increased by $0.1 million, or 13.0% and decreased by $0.2 million, or 6.6%, respectively, from the same periods in 2010. The quarterly increase is a result of the 2011 acquisitions along with increased drilling programs in both the Haynesville shale and Marcellus shale, whereas the decrease for year to date is partially 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 nine months ended September 30, 2011 and 2010:

	Three months ended September 30,						Quarter to quarter change			Nine months ended September 30,						Period to period  change
(in thousands, except per unit rate)	2011			2010			2011-2010			2011			2010			2011-2010
General and administrative costs:
Gross general and administrative expense	$	38,833		$	32,186		$	6,647		$	102,316		$	97,864		$	4,452
Operator overhead reimbursements		(4,859	)		(3,906	)		(953	)		(13,745	)		(11,778	)		(1,967	)
Capitalized acquisition and development charges		(4,099	)		(4,246	)		147			(12,136	)		(9,767	)		(2,369	)
Net general and administrative expense	$	29,875		$	24,034		$	5,841		$	76,435		$	76,319		$	116
General and administrative expense per Mcfe	$	0.60		$	0.82		$	(0.22	)	$	0.58		$	0.96		$	(0.38	)

Our general and administrative costs for the three months ended September 30, 2011 were $29.9 million, or $0.60 per Mcfe, compared to $24.0 million, or $0.82 per Mcfe, for the same period in 2010, an increase of $5.9 million, or 24.3%. Our general and administrative costs for the nine months ended September 30, 2011 were $76.4 million, or $0.58 per Mcfe, compared to $76.3 million, or $0.96 per Mcfe, for the same period in 2010, an increase of $0.1 million, or 0.2%.

Significant components of the net increase for the three and nine months ended September 30, 2011 compared to the respective 2010 periods were a result of:

• increased legal costs of $0.6 million for the three months ended September 30, 2011 due to various claims and settlements;

• increased environmental and safety costs of $0.5 million for the nine months ended September 30, 2011 due to costs incurred to develop waste management programs and to comply with certain new emission regulations;

• increased technology costs of $0.9 million and $1.0 million for the three and nine months ended September 30, 2011, respectively; and

• and increased personnel costs of $8.7 million and $14.5 million for the three and nine months ended September 30, 2011, respectively, due primarily to technical employees hired to develop our shale resource asset base and the retention bonus paid in the third quarter of 2011.

These increases were partially offset by:

• decreased office costs, including rent, of $1.0 million and $1.3 million for the three and nine months ended September 30, 2011, due to the 2010 termination of certain building leases in our Appalachia region and our office in the Woodlands, Texas;

• decreased relocation costs of $0.7 million and $0.5 million for the three and nine months ended September 30, 2011, respectively, due to the employees relocated and hired for the 2010 Appalachia JV;

• decreased franchise and property taxes of $0.9 million and $0.7 million for the three and nine months ended September 30, 2011, respectively;

• decreased share-based compensation costs of $2.6 million for the nine months ended September 30, 2011 due primarily to a reduction in options granted in 2010;

• increased capitalized charges of $2.4 million for the nine months ended September 30, 2011, respectively, primarily related to increased technical personnel;

43

• increased operator overhead recoveries of $1.0 million and $2.0 million for the three and nine months ended September 30, 2011, respectively, due to increased drilling in our shale plays; and

• increased recoveries of technical and administrative service costs of $1.9 million and $5.0 million from our service agreements with BG Group for the three and nine months ended September 30, 2011, respectively.

Other operating items

Our other operating expenses for the three and nine months ended September 30, 2011 were $21.0 million and $25.2 million, respectively, compared with $6.3 million and $5.7 million for the three and nine months ended September 30, 2010, respectively, excluding the nine months ended September 30, 2010 gain on divestiture of $574.8 million. The three and nine months ended September 30, 2011 balances include expenses related to accruals for various lawsuits, the impairment of certain treating facilities in our Vernon Field and the review of strategic alternatives by our special committee.

Interest expense

Our interest expense for the three and nine months ended September 30, 2011 increased $6.7 million and $10.0 million, respectively from the comparable 2010 periods. The $6.7 million increase for the three month period ended September 30, 2011 from the prior year’s quarter was due primarily to a net increase $4.7 million related to our 2018 and 2011 Notes and a $1.8 million increase on our EXCO Resources Credit agreement. The $10.0 million increase for the nine months ended September 30, 2011 compared with the prior year’s nine month period was due primarily to a net increase of $19.1 related to interest paid on our 2018 Notes compared to the 2011 Notes which was partially offset by $10.4 million of increase in capitalized interest.

	Three months ended September 30,						Quarter to quarter change			Nine months ended September 30,						Period to period  change
(in thousands)	2011			2010			2011-2010			2011			2010			2011-2010
Interest expense:
2018 Notes	$	14,330		$	2,385		$	11,945		$	42,975		$	2,385		$	40,590
2011 Notes (1)		—			7,293			(7,293	)		—			21,532			(21,532	)
EXCO Resources Credit Agreement		5,799			3,989			1,810			16,705			8,613			8,092
EXCO Operating Credit Agreement (2)		—			—			—			—			6,008			(6,008	)
Amortization and write-off of deferred financing costs on EXCO Resources Credit Agreement		1,837			1,223			614			4,131			2,516			1,615
Amortization of deferred financing costs on EXCO Operating Credit Agreement (2)		—			—			0			—			4,436			(4,436	)
Amortization of deferred financing costs on 2018 Notes		467			76			391			1,401			76			1,325
Interest rate swaps settlements		—			—			—			—			2,063			(2,063	)
Fair market value adjustment on interest rate swaps		—			—			—			—			(2,018	)		2,018
Capitalized interest		(7,407	)		(6,595	)		(812	)		(23,155	)		(12,709	)		(10,446	)
Other		64			69			(5	)		1,528			648			880
Total interest expense	$	15,090		$	8,440		$	6,650		$	43,585		$	33,550		$	10,035

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

(2) The EXCO Operating Credit Agreement was consoilidated 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.

44

	Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,					Period to period change
(in thousands)	2011		2010		2011-2010			2011		2010			2011-2010
Derivative financial instrument activities:
Cash settlements on derivative financial instruments, excluding early terminations	$	32,938	$	43,075	$	(10,137	)	$	83,090	$	128,724		$	(45,634	)
Cash settlements on early terminations of derivative financial instruments		—		—		—			—		37,936			(37,936	)
Non-cash change in fair value of derivative financial instruments		51,346		13,134		38,212			47,888		(10,595	)		58,483
Total derivative financial instrument activities	$	84,284	$	56,209	$	28,075		$	130,978	$	156,065		$	(25,087	)

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 $4.36 during the nine months ended September 30, 2011 from $4.77 during the nine months ended September 30, 2010. The impact of the cash settlements on our derivatives (excluding early terminated contracts in 2010) increased our price to $4.99 per Mcfe for the nine months ended September 30, 2011 and increased our price to $6.38 per Mcfe for the nine months ended September 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 $0.48 per Mcfe for the nine months ended September 30, 2010 to $6.86 per Mcfe.

	Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,				Period to period change
Realized pricing:	2011		2010					2011		2010
Oil per Bbl	$	85.69	$	72.85	$	12.84		$	91.53	$	74.13	$	17.40
Natural gas per Mcf		3.95		4.15		(0.20	)		4.08		4.47		(0.39	)
Natural gas equivalent per Mcfe	$	4.17	$	4.44	$	(0.27	)	$	4.36	$	4.77	$	(0.41	)
Cash settlements on derivatives, excluding early terminations, per Mcfe		0.66		1.46		(0.80	)		0.63		1.61		(0.98	)
Net price per Mcfe, including derivative financial instruments before early terminations	$	4.83	$	5.90	$	(1.07	)	$	4.99	$	6.38	$	(1.39	)
Cash settlements on early terminations of derivative financial instruments, per Mcfe		—		—		—			—		0.48		(0.48	)
Net price per Mcfe, derivative financial instruments	$	4.83	$	5.90	$	(1.07	)	$	4.99	$	6.86	$	(1.87	)

Our total cash settlements for the three months ended September 30, 2011 increased revenue by $32.9 million, or $0.66 per Mcfe, compared to $43.1 million, or $1.46 per Mcfe, for the same period in 2010. Our total cash settlements for the nine months ended September 30, 2011, including derivatives settled early, increased revenue by $83.1 million, or $0.63 per Mcfe, compared to cash settlements increasing revenues by $166.7 million, or $2.09 per Mcfe, for the same period in 2010. As noted above, the significant fluctuations between settlements of receipts on our derivative financial instruments demonstrates 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 nine months ended September 30, 2011 resulted in gains of $51.3 million and $47.9 million, respectively, compared to gains of $13.1 million and losses of $10.6 million, respectively, for the same periods 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 2011 is 0% and for the three and nine months ended September 30, 2010 was a benefit of 1.4% and an expense of 0.5%, 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 September 30, 2011 is approximately $311.9 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 nine months ended September 30, 2011 would have been 40.0%. For the three and nine months ended September 30, 2010, the effective income tax rates, excluding the impact of the valuation allowances, would have been 42.9% and 40.7%, respectively.

45

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 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. Continued volatility in natural gas prices may impact our development plans. If the current weaknesses in natural gas prices continue, we may reduce our future development plans.

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

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

• our ability to adjust our capital expenditure programs in response to increases or decreases in commodity prices;

• 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;

• 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 the 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 utilize available borrowing capacity under 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. Presently, our strategy is to primarily focus on our target areas in East Texas/North Louisiana and Appalachia for contiguous acreage blocks or “bolt-on” acreage, as economic conditions permit.

Our capital forecast for 2011 totals $1,014.4 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 September 30, 2011, approximately $78.8 million of the Appalachia Carry remained unused.

The following table presents capital expenditures for the first nine 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.

46

	Nine months ended September 30,		October  - December forecast		Full year forecast
(dollars in thousands)	2011		2011		2011
Capital expenditures:
Development capital expenditures	$	671,827	$	220,060	$	891,887
Lease purchases (1)		33,067		492		33,559
Seismic		7,960		4,733		12,693
Water pipelines and gas gathering		6,024		4,040		10,064
Corporate and other .		50,578		15,650		66,228
Total capital expenditures	$	769,456	$	244,975	$	1,014,431

(1) Net of acreage reimbursements from BG Group totaling $22.8 million to date in 2011 and $9.7 million expected in Q4 2011.

We are presently developing our 2012 capital expenditure budget.

Events affecting liquidity

On December 21, 2010, we funded the Chief Transaction, which included undeveloped acreage and oil and natural gas properties in the Marcellus shale for approximately $454.4 million ($227.2 million net to us) after post-closing adjustments.

The TGGT Credit Agreement closed on January 31, 2011 and a portion of the proceeds were used 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 October 27, 2011, the outstanding balance of the TGGT Credit Agreement was $462.1 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 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.

On April 5, 2011, we closed the Haynesville Shale Acquisition for $225.2 million which included 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 and 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.

In the second quarter 2011 an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana resulting in an immediate shut-down of the facility. As a precautionary measure, TGGT also shut down another amine treating facility located in DeSoto Parish with similar specifications, which was restarted in October 2011. TGGT has ordered temporary treating units and expects to be capable of treating all projected northwest Louisiana throughput volumes early in the first quarter of 2012 once these temporary treating units are operational. The estimated third quarter 2011 impact to TGGT resulting from this incident was an $8.7 million net decrease to their operating income, which was primarily due to an estimated $7.0 million reduction in revenue. TGGT received an initial insurance reimbursement associated with the incident of approximately $6.2 million during the third quarter 2011. TGGT expects to have the damaged facility re-commissioned late in the first quarter of 2012.

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

47

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.

Weakness in natural gas prices has persisted for the past three years, negatively impacting both our operating cash flows and the economics of many of our non-shale prospective well locations. Because of the high percentage of our potential drilling locations that are held by production, or in which we own the mineral interests, we have the capability to modify the timing and level of our development to better match our liquidity. 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.

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

(in thousands)	September 30, 2011		October 27, 2011
Cash (1)	$	173,757	$	230,939
Borrowings under the EXCO Resources Credit Agreement	$	972,500	$	1,032,500
2018 Notes (2)		750,000		750,000
Total debt		1,722,500		1,782,500
Net debt	$	1,548,743	$	1,551,561
Consolidated borrowing base	$	1,500,000	$	1,500,000
Total of unused borrowing base (3)	$	517,973	$	457,973
Unused borrowing base plus cash (1) (3)	$	691,730	$	688,912

(1) Includes restricted cash of $117.3 million at September 30, 2011 and $152.5 million at October 27, 2011.

(2) Excludes unamortized bond discount of $9.9 million at September 30, 2011 and October 27, 2011.

(3) Net of letters of credit of $9.5 million at September 30, 2011 and October 27, 2011.

Historical sources and uses of funds

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

	Nine months ended September 30,
(amounts in thousands)	2011			2010
Cash flows provided by operating activities	$	355,334		$	275,996
Cash flows used in investing activities		(446,402	)		(44,163	)
Cash flows provided by (used in) financing activities		103,257			(249,116	)
Net increase (decrease) in cash	$	12,189		$	(17,283	)

Our primary sources of cash in the first nine 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 $227.2 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 nine months ended September 30, 2011 was $355.3 million compared with $276.0 million for the nine months ended September 30, 2010. The 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 October 27, 2011, our cash and cash equivalent balance was $78.4 million and our restricted cash account, which is principally used for Haynesville/Bossier shale development operations, was $152.5 million.

48

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 shale areas. Our recent acquisitions have been focused primarily on undeveloped shale acreage in our core areas and have been funded primarily with borrowings under the EXCO Resources Credit Agreement. We also receive reimbursements from BG Group on these acquisitions as 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 nine month period ended September 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 $227.2 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 nine months ended September 30, 2011, our cash flows from financing activities were $103.3 million primarily from increases borrowings of $123.5 million under the EXCO Resources Credit Agreement.

EXCO Resources Credit Agreement and long-term debt

As of October 27, 2011, we had total debt outstanding of approximately $1.8 billion, consisting of borrowings under the EXCO Resources Credit Agreement of $1.0 million and $750.0 million of the 2018 Notes. Terms and conditions of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement, as amended, had a borrowing base of $1.5 billion and outstanding indebtedness of $972.5 million as of September 30, 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 EXCO Resources Credit 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 EXCO Resources Credit 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.

49

As of September 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 EXCO Resources Credit Agreement) of at least 1.0 to 1.0 as of the end of any fiscal quarter; and

• not permit our ratio of consolidated funded indebtedness to consolidated EBITDAX (as defined in the EXCO Resources Credit Agreement) to be greater than 4.0 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 September 30, 2011, $750.0 million in principal was outstanding on the 2018 Notes. The unamortized discount on the 2018 Notes at September 30, 2011 was $9.9 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $678.6 million on September 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.

50

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 October 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. The stock repurchase program was reinstated by the Board of Directors on August 5, 2011.

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 September 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:
Q4 2011		30,820	$	5.17		138	$	111.32
2012		80,520		5.27		275		95.70
2013		5,475		5.99

Off-balance sheet arrangements

We have no arrangements or any guarantees of off-balance sheet debt to third parties.

Contractual obligations and commercial commitments

	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
Long-term debt 2018 Notes (1)	$	—	$	—	$	—	$	750,000	$	750,000
Long-term debt - EXCO Resources Credit Agreement (2)		—		—		972,500		—		972,500
Firm transportation services (3)		90,396		185,793		175,373		417,120		868,682
Other fixed commitments (4)		113,318		114,720		16,473		3,002		247,513
Drilling contracts		113,864		49,053		12		—		162,929
Operating leases and other		14,777		23,168		6,872		280		45,097
Total contractual obligations	$	332,355	$	372,734	$	1,171,230	$	1,170,402	$	3,046,721

51

(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.

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

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2011
Natural gas:
Swaps:
Remainder of 2011		30,820	$	5.17	$	41,408
2012		80,520		5.27		80,896
2013		5,475		5.99		6,301
Total natural gas		116,815				128,605
Oil:
Swaps:
Remainder of 2011		138		111.32		4,323
2012		275		95.70		3,884
Total oil		413				8,207
Total oil and natural gas derivatives					$	136,812

52

At September 30, 2011, the average forward NYMEX oil prices per Bbl for the remainder of 2011 and for 2012 were $79.37 and $81.06, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2011 and for 2012 were $3.80 and $4.24, 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 September 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 138 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 138 Mbbls. For example, for a hedged volume of 138 Mbbls, if the settlement price is $112.32 per Bbl then other income would decrease by $0.1 million. Conversely, if the settlement price is $110.32 per Bbl, other income would increase by $0.1 million.

Interest rate risk

At September 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 September 30, 2011, we had approximately $972.5 million in outstanding borrowings under the EXCO Resources Credit Agreement. A 1% change in interest rates based on the variable borrowings as of September 30, 2011 would result in an increase or decrease in our interest costs of $9.7 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

Item 4. Controls and Procedures

Disclosure controls and procedures. Pursuant to Rule 13a-15(b) under the Exchange Act, 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 September 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.

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 September 30, 2011 that have materially affected, or are reasonably likely to materially affect, EXCO’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

In the ordinary course of business, we are periodically a party to 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 17. Former acquisition proposal” of the notes to our consolidated financial statements for information regarding lawsuits against the Company or members of the board of directors in connection with Mr. Miller’s former acquisition proposal that were terminated during the quarter ended September 30, 2011.

53

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 September 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)
July 1 - July 31, 2011		—	$	—		—	$	192.5 million
August 1 - August 31, 2011		—		—		—	$	192.5 million
September 1 - September 30, 2011		—		—		—	$	192.5 million
Total		—				—

(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 and on August 5, 2011, our Board of Directors agreed to reinstate the repurchase program.

Item 5. Other Information

Pennsylvania land title legal ruling

In September 2011, the Pennsylvania Superior Court (an intermediate Pennsylvania appellate court) rendered a decision, styled Butler v. Charles Powers Estate (“Butler”) that raises a potential Pennsylvania land title issue. In Butler, the Superior Court remanded the case back to the trial court for further proceedings to determine whether the heirs of a grantor of a deed who retained title in the grantor only for “minerals” and “petroleum oils” also retained title to the natural gas from the Marcellus shale formation.

For over 100 years, Pennsylvania courts have held that there is a rebuttable presumption that a grant or reservation of “minerals” in a deed generally does not mean that the parties intended to grant or reserve oil or natural gas. In other words, the courts will strictly interpret the language of the deed and any reservations. To overcome this presumption, a party must present “clear and convincing” evidence that the parties to the conveyance intended to include natural gas within the word “minerals”.

There is Pennsylvania case law that holds coal is a mineral and, therefore, whoever owns the coal also owns the coalbed methane gas found in place therein. The central question on remand to the trial court in the Butler decision is whether the Marcellus shale should be characterized as a “mineral”, like coal whoever has title to the Marcellus shale has title to the natural gas trapped therein. The Butler decision has been appealed to the Pennsylvania Supreme Court.

If the courts ultimately determined the Marcellus Shale is a “mineral” and the natural gas trapped therein belongs to the rightful owner of that “mineral”, then leases held by the Company (and other Marcellus Shale lessees) could be compromised in some cases and the company could be further exposed to claims regarding the ownership of natural gas it has already produced from existing Marcellus wells.

Title to oil and gas interests is typically not fully analyzed until closer in time to the commencement of drilling operations on the lease, due to the time and expense of detailed title examinations. Curative title requirements are typically identified that are satisfied prior to the actual drilling of wells. The Company will address this title uncertainty similar to other customary title issues that arise in the normal course of our business.

The Company is currently conducting an intensive review of its Pennsylvania leases focusing first on leases that the Company intends to drill on in the next year or leases that are part of units that the Company intends to drill on in the next year.

54

Item 6. Exhibits

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

SIGNATURES

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

EXCO RESOURCES, INC.
(Registrant)
Date: November 2, 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

55

INDEX TO EXHIBITS

Exhibit Number	Description of Exhibits
2.1	Membership Interest Transfer Agreement, dated as of May 9, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
2.2	First Amendment to Membership Interest Transfer Agreement, dated as of June 1, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated herein by reference.
2.3	Second Amendment to Membership Interest Transfer Agreement, dated as of June 30, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated herein by reference.
2.4	Amendment to Membership Interest Transfer Agreement, dated as of November 24, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated herein by reference.
2.5	Fourth Amendment to Membership Interest Transfer Agreement, dated as of January 6, 2011, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated herein by reference.
2.6	Fifth Amendment to Membership Interest Transfer Agreement, dated as of January 13, 2011, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated herein by reference.
2.7	Sixth Amendment to Membership Interest Transfer Agreement, dated as of March 24, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on May 4, 2011 and incorporated by reference herein.
2.8	Seventh Amendment to Membership Interest Transfer Agreement, dated as of June 16, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q filed on August 3, 2011 and incorporated by reference herein.
3.1	Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K (File No. 001-32743), dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.
3.2	Articles of Amendment to the Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, 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.

56

3.8	Statement of Designation of Series A-l Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
3.9	Statement of Designation of Series A-2 Hybrid Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
3.10	Statement of Designation of Series A Junior Participating Preferred Stock of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K dated January 12, 2011 and filed on January 13, 2011 and incorporated by reference herein.
4.1	Indenture, dated September 15, 2010, by and between EXCO Resources, Inc. and Wilmington Trust Company, as trustee, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.
4.2	First Supplemental Indenture, dated September 15, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries and Wilmington Trust Company, as trustee, including the form of 7.500% Senior Notes due 2018, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.
4.3	Specimen Stock Certificate for EXCO’s common stock, filed as an Exhibit to EXCO’s Amendment No. 2 to the Form S-l (File No. 333-129935) filed on January 27, 2006 and incorporated by reference herein.
4.4	First Amended and Restated Registration Rights Agreement, by and among EXCO Holdings Inc. and the Initial Holders (as defined therein), effective January 5, 2006, filed as an Exhibit to EXCO’s Amendment No. 1 to its Registration Statement on Form S-l (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
4.5	Rights Agreement, dated as of January 12, 2011, by and between EXCO Resources, Inc. and Continental Stock Transfer & Trust Company, as Rights Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K dated January 12, 2011 and filed on January 13, 2011 and incorporated by reference herein.
4.6	Amendment No. 1 to Rights Agreement, dated as of August 19, 2011, by and between EXCO Resources, Inc. and Continental Stock Transfer & Trust Company, as Rights Agent, filed as an Exhibit to EXCO’s Form 8-A/A, filed on August 22, 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 Current Report on Form 8-K, dated August 4, 2011 and filed on August 10, 2011 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.

57

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	Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.
10.12	Amendment Number Two to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, dated as of October 6, 2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated October 6, 2011 and filed on October 7, 2011 and incorporated by reference herein.*
10.13	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.
10.14	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.
10.15	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.
10.16	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.
10.17	Joint Development Agreement, dated as of June 1, 2010, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.18	Amendment to Joint Development Agreement, dated February 4, 2011, by and among EXCO Production Company (PA), LLC, EXCO Production Company (WV), LLC, BG Production Company, (PA), LLC, BG Production Company, (WV), LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2010 filed February 24, 2011 and incorporated herein by reference.
10.19	Second Amended and Restated Limited Liability Company Agreement of EXCO Resources (PA), LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.20	Second Amended and Restated Limited Liability Company Agreement of Appalachia Midstream, LLC, dated June 1, 2010, by and among EXCO Holding (PA), Inc., BG US Production Company, LLC and Appalachia Midstream, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.21	Letter Agreement, dated June 1, 2010 and effective as of May 9, 2010, by and between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
10.22	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.
10.23	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.

58

10.24	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.
10.25	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.
10.26	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.
10.27	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.
10.28	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.
10.29	Seventh Amendment to Membership Interest Transfer Agreement, dated as of June 16, 2011, between EXCO Holding (PA), Inc., BG US Production Company, LLC and EXCO Resources (PA), LLC, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 3, 2011 and incorporated by reference herein.
10.30	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.
10.31	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.
10.32	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.
10.33	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.
10.34	Credit Agreement, dated as of April 30, 2010, among EXCO Resources, Inc., as Borrower, certain subsidiaries of Borrower, as Guarantors, the lenders party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Book runner and Lead Arranger, Wells Fargo Securities, LLC, as Co-Lead Arranger, Bank of America, N.A. and BNP Paribas, as Co-Lead Arrangers and Co-Syndication Agents, Royal Bank of Canada, as Co-Lead Arranger and Co-Documentation Agent, Wells Fargo Bank, National Association, as Co-Documentation Agent, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated July 16, 2010 and filed on July 22, 2010 and incorporated by reference herein.
10.35	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.
10.36	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.
10.37	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,

59

	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.
10.38	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.
10.39	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.
10.40	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.
10.41	EXCO Resources, Inc. Retention Bonus Plan, dated August 4, 2011, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 4, 2011 and filed on August 10, 2011 and incorporated by reference herein.*
31.1	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.
31.2	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.
32.1	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., furnished 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.

60