Exco Resources (EXCO) 10-Q 2010 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, 2010

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 29, 2010 was 212,309,253.

EXCO RESOURCES, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3
Item 1.	Financial Statements	3
	Condensed Consolidated Balance Sheets at September 30, 2010 and December 31, 2009	3
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009	5
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009	6
	Condensed Consolidated Statements of Changes in Shareholders’ Equity for the Nine Months Ended September 30, 2010 and 2009	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	55
Item 4.	Controls and Procedures	57
PART II.	OTHER INFORMATION	57
Item 1A.	Risk Factors	57
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 6.	Exhibits	61
	Signatures	62
	Index to Exhibits	63

2

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)	September 30, 2010			December 31, 2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	51,124		$	68,407
Restricted cash		100,249			58,909
Accounts receivable, net:
Oil and natural gas		64,809			56,485
Joint interest		103,698			47,104
Interest and other		24,749			10,832
Inventory		13,426			15,830
Derivative financial instruments		110,819			138,120
Other		20,838			6,401
Total current assets		489,712			402,088
Equity investments		326,317			216,987
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		633,273			492,882
Proved developed and undeveloped oil and natural gas properties		2,244,552			1,875,749
Accumulated depletion		(1,257,678	)		(1,132,604	)
Oil and natural gas properties, net		1,620,147			1,236,027
Gas gathering assets		153,712			180,506
Accumulated depreciation and amortization		(22,701	)		(22,841	)
Gas gathering assets, net		131,011			157,665
Office, field equipment and other, net		42,293			31,771
Deferred financing costs, net		32,081			7,602
Derivative financial instruments		40,964			34,677
Goodwill		218,256			269,656
Other assets		11,234			2,421
Total assets	$	2,912,015		$	2,358,894

See accompanying notes.

3

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share and share data)	September 30, 2010			December 31, 2009
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	124,182		$	112,991
Revenues and royalties payable		125,806			79,356
Accrued interest payable		3,923			16,193
Current portion of asset retirement obligations		900			900
Income taxes payable		0			210
Derivative financial instruments		0			3,264
Total current liabilities		254,811			212,914
Long-term debt, net of current maturities		993,417			1,196,277
Deferred income taxes		0			0
Derivative financial instruments		2,515			11,688
Asset retirement obligations and other long-term liabilities		61,401			78,427
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding		0			0
Common stock, $0.001 par value; 350,000,000 authorized shares; 212,718,779 shares issued and 212,179,558 shares outstanding at September 30, 2010; 211,905,509 shares issued and outstanding at December 31, 2009		213			212
Additional paid-in capital		3,129,460			3,105,238
Accumulated deficit		(1,522,323	)		(2,245,862	)
Treasury stock, at cost; 539,221 shares at September 30, 2010		(7,479	)		0
Total shareholders’ equity		1,599,871			859,588
Total liabilities and shareholders’ equity	$	2,912,015		$	2,358,894

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)	2010			2009			2010			2009
Revenues:
Oil and natural gas	$	130,990		$	125,493		$	380,328		$	443,953
Midstream		—			5,375			—			35,330
Total revenues		130,990			130,868			380,328			479,283
Costs and expenses:
Oil and natural gas production		25,140			43,026			83,222			144,538
Midstream operating		—			5,411			—			35,580
Gathering and transportation		11,561			4,927			35,547			12,879
Depreciation, depletion and amortization		53,687			50,709			137,844			187,683
Write-down of oil and natural gas properties		0			0			0			1,293,579
Accretion of discount on asset retirement obligations		830			1,767			2,920			5,856
General and administrative		24,034			21,647			76,319			64,682
Gain on divestitures and other operating items		6,257			(460,641	)		(569,096	)		(452,664	)
Total costs and expenses		121,509			(333,154	)		(233,244	)		1,292,133
Operating income (loss)		9,481			464,022			613,572			(812,850	)
Other income (expense):
Interest expense		(8,440	)		(46,737	)		(33,550	)		(129,760	)
Gain on derivative financial instruments		56,209			14,518			156,065			204,885
Other income (expense)		67			32			184			67
Equity income (loss)		6,675			(426	)		12,054			(426	)
Total other income (expense)		54,511			(32,613	)		134,753			74,766
Income (loss) before income taxes		63,992			431,409			748,325			(738,084	)
Income tax expense (benefit)		(904	)		(1,921	)		3,548			189
Net income (loss)	$	64,896		$	433,330		$	744,777		$	(738,273	)
Earnings (loss) per common share:
Basic
Net income (loss)	$	0.31		$	2.05		$	3.51		$	(3.50	)
Weighted average common shares outstanding		212,480			211,266			212,356			211,118
Diluted
Net income (loss)	$	0.30		$	2.03		$	3.45		$	(3.50	)
Weighted average common and common equivalent shares outstanding		214,922			213,235			215,627			211,118

See accompanying notes.

5

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine months ended September 30,
(in thousands)	2010			2009
Operating Activities:
Net income (loss)	$	744,777		$	(738,273	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		137,844			187,683
Stock option compensation expense		10,868			9,863
Accretion of discount on asset retirement obligations		2,920			5,856
Write-down of oil and natural gas properties		0			1,293,579
Gain on divestitures		(574,750	)		(460,626	)
(Income) loss from equity investments		(12,054	)		426
Non-cash change in fair value of derivatives		8,577			144,996
Cash settlements of assumed derivatives		907			(141,782	)
Deferred income taxes		0			(711	)
Amortization of deferred financing costs, discount on the 2018 Notes and premium on the 2011 Notes		3,077			44,327
Effect of changes in:
Accounts receivable		(89,298	)		66,961
Other current assets		(4,579	)		(5,094	)
Accounts payable and other current liabilities		47,707			(57,348	)
Net cash provided by operating activities		275,996			349,857
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(392,370	)		(388,859	)
Property acquisitions		(495,708	)		(67,774	)
Restricted cash		(41,340	)		(69,983	)
Deposit on pending divestitures		0			14,500
Investment in equity investments		(100,000	)		(47,500	)
Proceeds from disposition of property and equipment		995,573			1,409,378
Advances to Appalachia JV		(10,318	)		0
Net cash provided by (used in) investing activities		(44,163	)		849,762
Financing Activities:
Borrowings under credit agreements		1,402,399			52,949
Repayments under credit agreements		(1,895,563	)		(1,380,740	)
Proceeds from issuance of 2018 Notes		738,975			0
Repayment of 2011 Notes		(444,720	)		0
Proceeds from issuance of common stock		9,776			5,400
Payment of common stock dividends		(21,238	)		0
Payment for common shares repurchased		(7,479	)		0
Settlements of derivative financial instruments with a financing element		(907	)		141,782
Deferred financing costs and other		(30,359	)		(20,468	)
Net cash used by financing activities		(249,116	)		(1,201,077	)
Net decrease in cash		(17,283	)		(1,458	)
Cash at beginning of period		68,407			57,139
Cash at end of period	$	51,124		$	55,681
Supplemental Cash Flow Information:
Cash interest payments	$	52,424		$	90,010
Income tax payments	$	5,460		$	0
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	3,537		$	2,122
Capitalized interest	$	12,709		$	3,937
Issuance of common stock for director services	$	42		$	50

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, 2008		210,969	$	211		0		0		$	3,070,766	$	(1,738,476	)	$	1,332,501
Issuance of common stock		539		1							5,450					5,451
Share-based compensation											11,984					11,984
Net loss													(738,273	)		(738,273	)
Balance at September 30, 2009		211,508	$	212		0	$	0		$	3,088,200	$	(2,476,749	)	$	611,663
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	)
Net income													744,777			744,777
Treasury Stock						539		(7,479	)							(7,479	)
Balance at September 30, 2010		212,719	$	213		539	$	(7,479	)	$	3,129,460	$	(1,522,323	)	$	1,599,871

See accompanying notes.

7

EXCO RESOURCES, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Organization and basis of presentation

Unless the context requires otherwise, references in this quarterly report on Form 10-Q to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore North American oil and natural gas properties. Our principal operations are conducted in key North American 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.

We expect to continue to grow by leveraging our management and technical team’s experience, developing our shale resource plays, exploiting our multi-year inventory of development drilling locations and pursuing opportunistic acquisitions. 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, 2010 and December 31, 2009, the Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009, the Condensed Consolidated Statements of Cash Flows and Condensed Consolidated Statements of Changes in Shareholders’ Equity for the nine months ended September 30, 2010 and 2009 are for EXCO and its subsidiaries. The consolidated financial statements and related footnotes are presented in accordance with accounting principles generally accepted in the United States of America, or GAAP. All intercompany transactions have been eliminated.

We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission, or the SEC, and in the opinion of management, such financial statements reflect all adjustments necessary to present fairly the consolidated financial position of EXCO at September 30, 2010 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 financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2009.

In August 2009, we discontinued reporting our midstream operations as a separate business segment in connection with the sale to an affiliate of BG Group plc, or BG Group, of a 50% interest in a newly formed company, TGGT Holdings, LLC, or TGGT, which now holds most of our East Texas/North Louisiana midstream assets.

Beginning December 31, 2009, we reclassified certain items that relate to our operations from “Other income” into “Other operating items.” Prior year amounts have been reclassified to conform to the current year presentation.

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

2. Significant recent activities

Issuance of 7.5% Senior Notes due 2018 and Retirement of the 7 ¹/4% Senior Notes due 2011

On September 15, 2010, we closed our underwritten offering of $750.0 million aggregate principal amount of 7.5% Senior Notes due 2018, or the 2018 Notes. We received proceeds of approximately $724.4 million from the offering, after deducting an original issue discount of $11.0 million and commissions, estimated offering fees and expenses of $14.6 million. We used a portion of the net proceeds from the offering to redeem all of our $444.7 million outstanding 7 ¹/4% Senior Notes due 2011, or the 2011 Notes, in accordance with the terms of the indenture under which those notes were issued.

8

Amendment and restatement of the EXCO Resources Credit Agreement

On April 30, 2010, we amended and restated the EXCO Resources credit agreement to consolidate the EXCO Resources credit agreement and the EXCO Operating credit agreement into one credit agreement, or the EXCO Resources Credit Agreement. Among other things, under the terms of the amended and restated agreement, EXCO Operating Company, LP, or EXCO Operating, and certain of its subsidiaries became guarantor subsidiaries under the EXCO Resources Credit Agreement. The EXCO Resources Credit Agreement matures on April 30, 2014.

Common Transaction

On May 14, 2010, EXCO and BG Group closed the joint purchase of Common Resources, L.L.C., or the Common Transaction, which owns properties in Shelby, San Augustine and Nacogdoches Counties, Texas in the Haynesville and Bossier shales. The total purchase price paid at closing was approximately $442.1 million ($221.0 million net to EXCO), subject to post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under the EXCO Resources Credit Agreement. The development of these assets is governed by our East Texas/North Louisiana joint venture with BG Group, or the East Texas/North Louisiana JV.

Appalachia JV

On June 1, 2010, we closed a transaction which resulted in the sale of a 50% undivided interest in substantially all of our Appalachian oil and natural gas proved and unproved properties and related assets to BG Group for cash consideration of approximately $835.2 million, subject to customary final closing adjustments, or the Appalachia JV. In addition to the cash consideration received at closing, BG Group agreed to fund 75% of our share of deep drilling and completion costs within our joint venture area until the carry amount is satisfied up to a total of $150.0 million. In conjunction with the Appalachia JV, we entered into a Joint Development Agreement, or the Appalachia JDA, with BG Group. The effective date of the transaction was January 1, 2010.

EXCO and BG Group each own a 50% interest in an operating company, EXCO Resources (PA), LLC, or OPCO, which operates the properties located within the Appalachia JV, subject to oversight from a management board having equal representation from EXCO and BG Group. On June 1, 2010, we made a $33.0 million advance to OPCO to provide working capital for our share of properties. This advance was recorded as a prepaid asset and included in “Other” current assets on our Condensed Consolidated Balance Sheets and will be offset by any payments made by OPCO for our interest in the properties. We will continue to fund OPCO with advances to develop the Appalachia properties. We use the equity method to account for our 50% interest in OPCO.

In addition to the upstream Appalachia properties, certain midstream assets were transferred to a newly formed, jointly owned entity, Appalachia Midstream, LLC, through which both EXCO and BG Group will pursue the construction and expansion of gathering systems, pipeline systems and treating facilities for anticipated future production from the Marcellus shale. We use the equity method to account for our 50% interest in Appalachia Midstream, LLC.

The Appalachia JV caused a significant alteration to our full cost pool and a gain, including a proportionate net reduction in goodwill, of approximately $575.0 million was recognized during the second quarter of 2010.

Southwestern Transaction

On June 30, 2010, EXCO and BG Group closed the joint purchase of properties in Shelby, San Augustine and Nacogdoches Counties, Texas in the Haynesville and Bossier shales from Southwestern Energy Company, or the Southwestern Transaction. The purchase price paid at the closing was $355.8 million ($177.9 million net to EXCO), subject to customary post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under the EXCO Resources Credit Agreement. The development of these assets is governed by the East Texas/North Louisiana JV. The majority of the assets acquired in the Southwestern Transaction represented incremental working interests in properties that EXCO and BG Group acquired in the Common Transaction.

3. Recent accounting pronouncements

On January 21, 2010, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2010-06—Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed. Fair value measurements using significant unobservable inputs should be presented on a gross basis and the fair value measurement disclosure should be reported for each class of asset and liability. Disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements will be required for fair value measurements that fall in either Level 2 or 3. The update is effective for interim and annual reporting periods beginning after December 15, 2009. See “Note 9. Derivative financial instruments and fair value measurements” for the impact to our disclosures.

9

4. Significant accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, estimates of Proved Reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as significant accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies and others are summarized in our Annual Report on Form 10-K for the year ended December 31, 2009.

5. Asset retirement obligations

The following is a reconciliation of our asset retirement obligations for the nine months ended September 30, 2010:

(in thousands)
Asset retirement obligations at January 1, 2010	$	65,115
Activity during the nine months ended September 30, 2010:
Liabilities incurred during the period		1,063
Liabilities settled during the period		(503	)
Reduction to retirement obligations due to divestitures		(19,817	)
Accretion of discount		2,920
Asset retirement obligations at September 30, 2010		48,778
Less current portion		(900	)
Long-term portion	$	47,878

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

6. Oil and natural gas properties

The accounting for, and disclosure of, oil and natural gas producing activities require that we choose between two GAAP alternatives; the full cost method or the successful efforts method. We use the full cost method of accounting, which involves capitalizing all exploration, exploitation, development and acquisition costs. When we incur intangible drilling costs, lease and well equipment, exploration and development costs, they are recorded in the depletable pool of proved properties. Costs for unproved properties, which included capitalized interest, totaled $633.3 million and $492.9 million as of September 30, 2010 and December 31, 2009, respectively, are not subject to depletion. The sum of the depletable costs plus the unproved properties are collectively defined as the full cost pool. The $140.4 million increase in our unproved properties between December 31, 2009 and September 30, 2010 was due primarily to the properties purchased in the Common Transaction and the Southwestern Transaction, offset by reimbursements of acreage costs from BG Group in the Haynesville area and elimination of all of our unproved property costs as of June 1, 2010 arising from the gain computation in the Appalachia area as a result of the Appalachia JV. 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. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. No impairment of undeveloped properties occurred during the third quarter of 2010.

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 began capitalizing interest in April 2008, upon identification and development of shale resource opportunities in the Haynesville and Marcellus areas. The amount of interest capitalized, net of any amounts sold, amortized or transferred into the depletable full cost pool, was $14.1 million as of September 30, 2010. When the balance is moved to proved developed and undeveloped oil and natural gas properties, or the properties are sold, we will 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 unit-of-production rate is applied to our total production for the period, and the appropriate expense is recorded. We capitalize the portion of general and administrative costs, including share-based compensation, that is attributable to our exploration, exploitation and development activities.

10

Divestitures 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 unit-of-production rate and/or the relationship between capitalized costs and Proved Reserves. In the event a divestiture results in a significant alteration to our full cost pool, we also record a proportionate reduction of goodwill associated with our oil and natural gas properties.

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 perform 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 to the full cost ceiling. The full cost ceiling limitation is computed as the sum of the present value of estimated future net revenues from our Proved Reserves by applying average prices as prescribed by the SEC’s 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 nine months ended September 30, 2010, the trailing twelve month reference price was $77.34 per Bbl for the West Texas Intermediate oil at Cushing, Oklahoma and $4.41 per Mmbtu for natural gas at Henry Hub. Each of the aforementioned reference prices for oil and natural gas are further adjusted for quality factors and regional differentials to derive estimated future net revenues. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods. Since we do not designate our derivative financial instruments as hedges, we are not allowed to use the impacts of the derivative financial instruments in our ceiling test computation. As a result, decreases in commodity prices which contribute to ceiling test write-downs may be offset by mark-to-market gains which are not reflected in our ceiling test results. There were no ceiling test write-downs for the three or nine months ended September 30, 2010.

For the nine months ended September 30, 2009, we recognized a ceiling test write-down of approximately $1.3 billion to our proved oil and natural gas properties. This write-down occurred in the first quarter of 2009. Under the full cost accounting rules in place prior to the SEC’s Release No. 33-8995 on December 31, 2009, the SEC required the full cost ceiling to be computed using spot market prices for oil and natural gas at our balance sheet date.

The ceiling test calculation is based upon estimates of Proved Reserves. There are numerous uncertainties inherent in estimating quantities of Proved Reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

7. Earnings (loss) 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 (loss) per share for the three and nine months ended September 30, 2010 and 2009 equals the net income (loss) divided by the weighted average common shares outstanding during the periods. Diluted earnings (loss) per common share for the three and nine months ended September 30, 2010 and 2009 are computed in the same manner as basic earnings (loss) per share after assuming issuance of common stock for all potentially dilutive common stock equivalents, whether exercisable or not. Common stock equivalents of 6,603,877 and 4,090,014 were excluded from the three and nine months ended September 30, 2010 computation of diluted earnings per share. Common stock equivalents of 4,180,682 were excluded from the three months ended September 30, 2009 computation of diluted earnings per share. Since we incurred a net loss for the nine months ended September 30, 2009, we excluded 14,677,233 common stock equivalents from the diluted earnings per share.

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

	Three months ended September 30,				Nine months ended September 30,
(in thousands, except per share amount)	2010		2009		2010		2009
Basic income (loss) per common share:
Net income (loss)	$	64,896	$	433,330	$	744,777	$	(738,273	)
Shares:
Weighted average number of common shares outstanding		212,480		211,266		212,356		211,118
Basic income (loss) per common share:
Net income (loss) per common share	$	0.31	$	2.05	$	3.51	$	(3.50	)
Diluted income (loss) per share:
Net income (loss)	$	64,896	$	433,330	$	744,777	$	(738,273	)
Shares:
Weighted average number of common shares outstanding		212,480		211,266		212,356		211,118
Dilutive effect of stock options		2,442		1,969		3,271		—
Weighted average number of common shares and common stock equivalent shares outstanding		214,922		213,235		215,627		211,118
Diluted income (loss) per share:
Net income (loss) per common share	$	0.30	$	2.03	$	3.45	$	(3.50	)

8. Stock options

We account for stock options in accordance with FASB ASC Topic 718 for Compensation – Stock Compensation Topic, or ASC 718. As required by ASC 718, the granting of options to our employees under our 2005 Long-Term Incentive Plan, or the 2005 Incentive Plan, are share-based payment transactions and are to be treated as compensation expense by us with a corresponding increase to additional paid-in capital. Volatility is determined based on the combination of the weighted average volatility of our common stock price and the weighted average volatility from five comparable public companies during the period when we were privately held. Total share-based compensation to be recognized on unvested awards as of September 30, 2010 is $20.7 million over a weighted average period of 1.47 years.

The following is a reconciliation of our stock option expense for the three and nine months ended September 30, 2010 and 2009:

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2010		2009		2010		2009
General and administrative expense	$	2,166	$	2,764	$	10,028	$	7,865
Lease operating expense		239		619		840		1,998
Total share-based compensation expense		2,405		3,383		10,868		9,863
Share-based compensation capitalized		1,362		942		3,537		2,122
Total share-based compensation	$	3,767	$	4,325	$	14,405	$	11,985

During the nine months ended September 30, 2010, options to purchase 489,600 shares were granted under the 2005 Incentive Plan at prices ranging from $13.97 to $22.22 per share with fair values ranging from $7.34 to $12.77 per share. During the nine months ended September 30, 2009, options to purchase 317,600 shares were granted under the 2005 Incentive Plan at prices ranging from $7.89 to $16.29 per share with fair values ranging from $4.89 to $10.44 per share. The options expire ten years following the date of grant. Pursuant to the 2005 Incentive Plan, 25% of the options vest immediately with an additional 25% to vest on each of the next three anniversaries of the date of the grant. As of September 30, 2010 and December 31, 2009, there were 3,691,175 and 3,920,100 shares available for grant under the 2005 Incentive Plan, respectively.

In connection with certain divestitures, 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 of 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.

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9. Derivative financial instruments and fair value measurements

Our objective in entering into derivative financial instruments is to manage exposure to commodity price and interest rate 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 or increases in interest rates, but also limit the benefits we would realize if commodity prices increase or interest rates decrease. When prices for oil and natural gas or interest rates are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expense due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration.

We account for our derivative financial instruments in accordance with FASB ASC Topic 815 for Derivatives and Hedging, or ASC 815, which requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. ASC 815 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met, or exemptions for normal purchases and normal sales as permitted by ASC 815 exist. We do not designate our derivative financial instruments as hedging instruments for financial accounting purposes and, as a result, we recognize the change in the respective instruments’ fair value currently in earnings. The table below outlines the classification of our derivative financial instruments on our Condensed Consolidated Balance Sheets and their financial impact in our Condensed Consolidated Statement of Operations.

Fair Value of Derivative Financial Instruments

(in thousands)	Balance Sheet location	September 30, 2010			December 31, 2009
Commodity contracts	Derivative financial instruments - Current assets	$	110,819		$	138,120
Commodity contracts	Derivative financial instruments - Long-term assets		40,964			34,677
Commodity contracts	Derivative financial instruments - Current liabilities		—			(1,246	)
Commodity contracts	Derivative financial instruments - Long-term liabilities		(2,515	)		(11,688	)
Interest rate contracts	Derivative financial instruments - Current liabilities		—			(2,018	)
Net derivative financial instruments		$	149,268		$	157,845

The Effect of Derivative Financial Instruments

		Three months ended September 30,					Nine months ended September 30,
(in thousands)	Statements of Operations location	2010		2009			2010			2009
Commodity contracts (1)	Gain (loss) on derivative financial instruments	$	56,209	$	14,518		$	156,065		$	204,885
Interest rate contracts (2)	Interest (expense) income		—		(3,304	)		(45	)		(3,785	)
Net gain (loss)		$	56,209	$	11,214		$	156,020		$	201,100

(1) Included in these amounts are net cash receipts of $43,075 and $166,660 for the three and nine months ended September 30, 2010, respectively, and net cash receipts of $113,563 and $354,131 for the three and nine months ended September 30, 2009, 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, respectively, and net cash payments of $3,500 and $8,036 for the three and nine months ended September 30, 2009, respectively. 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, 2010.

Settlements in the normal course of maturities of our derivative financial instrument contracts result in cash receipts from, or cash disbursements to, our derivative contract counterparties. Changes in the fair value of our derivative financial instrument contracts are included in income currently with a corresponding increase or decrease in the balance sheet fair value amounts. Unrealized fair value adjustments included in “Gain (loss) on derivative financial instruments,” which do not impact cash flows, were gains of $13.1 million and losses of $99.0 million for the three months ended September 30, 2010 and 2009, respectively, and were losses of $10.6 million and $149.2 million for the nine months ended September 30, 2010 and 2009, respectively. Unrealized fair value adjustments included in “Interest expense,” which do not impact cash flows, were a gain of $0.2 million for the three months ended September 30, 2009 and gains of $2.0 million and $4.3 million for the nine months ended September 30, 2010 and 2009, respectively. There was no impact 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, 2010.

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. As of September 30, 2010 and December 31, 2009, we had a net asset position of $149.3 million and $157.8 million, respectively.

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Fair value measurements

We value our derivatives according to FASB ASC Topic 820 for Fair Value Measurements and Disclosures, which defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. This fair value may be different from the settlement value based on company-specific inputs, such as credit rating, futures markets and forward curves, and readily available buyers or sellers for such assets or liabilities.

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

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

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

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

The following presents a summary of the estimated fair value of our derivative financial instruments as of September 30, 2010 and as of December 31, 2009:

	For the nine months ended September 30, 2010
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	149,268		$	—	$	149,268
	For the year ended December 31, 2009
(in thousands)	Level 1		Level 2			Level 3		Total
Oil and natural gas derivative financial instruments	$	—	$	159,863		$	—	$	159,863
Interest rate swaps		—		(2,018	)		—		(2,018	)
	$	—	$	157,845		$	—	$	157,845

We evaluate derivative assets and liabilities in accordance with master netting agreements with the derivative counterparties, but report them gross on the Condensed Consolidated Balance Sheets. Net derivative asset values are determined primarily by quoted futures prices and utilization of the counterparties’ credit-adjusted risk-free rate curves and net derivative liabilities are determined by utilization of our credit-adjusted risk-free rate curve. The credit-adjusted risk-free rates of our counterparties are based on an independent market-quoted credit default swap rate curve for the counterparties’ debt plus the London Interbank Offered Rate, or LIBOR, curve as of the end of the reporting period. Our credit-adjusted risk-free rate is based on the blended rate of independent market-quoted credit default swap rate curves for companies that have the same credit rating as us plus the LIBOR curve as of the end of the reporting period.

Oil and natural gas derivatives

Our commodity price derivatives represent oil and natural gas swap contracts. We have classified our oil and natural gas swaps and their related fair value tier as Level 2.

Oil derivatives. Our oil derivatives are swap contracts for notional Bbls of oil at fixed NYMEX West Texas Intermediate, or 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 natural gas at posted price indexes, using NYMEX Henry Hub. 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 Henry Hub for natural gas swaps for our existing basis swaps and (iii) the applicable credit-adjusted risk-free rate curve, as described above.

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The following table presents our financial assets and liabilities for oil and natural gas derivative financial instruments measured at fair value as of September 30, 2010:

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2010
Natural gas:
Swaps:
Remainder of 2010		13,940	$	7.21	$	45,081
2011		31,025		6.55		64,547
2012		16,470		6.05		15,793
2013		5,475		5.99		3,737
Total natural gas		66,910				129,158
Oil:
Swaps:
Remainder of 2010		113		114.96		3,763
2011		548		111.32		14,373
2012		92		109.30		1,974
Total oil		753				20,110
Total oil and natural gas and derivatives					$	149,268

At December 31, 2009, we had outstanding derivative contracts to mitigate price volatility covering 88,213 Mmcf of natural gas and 995 Mbbls of oil. At September 30, 2010, the average forward NYMEX oil prices per Bbl for the remainder of 2010 and for 2011 were $81.20 and $84.83, respectively, and the average forward NYMEX natural gas price per Mmbtu for the remainder of 2010 and for 2011 were $3.94 and $4.44, respectively.

Our derivative financial instruments covered 49.6% and 56.2% for the three and nine months ended September 30, 2010, respectively, and 80.9% and 76.8% for the three and nine months ended September 30, 2009, respectively, of our total expected equivalent Mcfe production.

Interest rate swaps

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal of our credit agreements through February 14, 2010 at LIBOR ranging from 2.45% to 2.8%. The net derivative liability value attributable to our interest rate derivative contracts as of the end of the reporting period are based on (i) the contracted notional amounts, (ii) forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. We classified our interest rate swaps and their related fair value tier as Level 2.

During the nine months ended September 30, 2010, we recognized increases of $0.1 million to interest expense on our interest rate swaps. During the three and nine months ended September 30, 2009, we recognized increases of $3.3 million and $3.8 million, respectively, to interest expense on our interest rate swaps. There was no impact 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, 2010.

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 2018 Notes is $740.6 million with a carrying amount of $739.0 million as of September 30, 2010. The estimated fair value has been calculated based on market quotes.

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10. Long-term debt

Our total debt is summarized as follows:

(in thousands)	September 30, 2010			December 31, 2009
EXCO Resources Credit Agreement	$	254,400		$	81,486
EXCO Operating credit agreement (1)		—			666,078
2018 Notes (2)		750,000			—
Unamortized discount on 2018 Notes		(10,983	)		—
2011 Notes (2)		—			444,720
Unamortized premium on 2011 Notes		—			3,993
Total debt	$	993,417		$	1,196,277

(1) On April 30, 2010, the EXCO Operating credit agreement was consolidated into the EXCO Resources Credit Agreement.

(2) On September 15, 2010, we issued the 2018 Notes and used a portion of the proceeds to redeem the 2011 Notes.

As of September 30, 2010, we had total debt outstanding of approximately $1.0 billion consisting of borrowings under our EXCO Resources Credit Agreement of $254.4 million and $750.0 million of 2018 Notes. Terms and conditions of each of the debt obligations are discussed below.

EXCO Resources Credit Agreement

As of September 30, 2010, the EXCO Resources Credit Agreement had a borrowing base of $1.2 billion, with $254.4 million of outstanding indebtedness and $930.4 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 October 6, 2010, the lenders completed their regular semi-annual redetermination of the borrowing base, resulting in a borrowing base of $1.0 billion following the offering of the 2018 Notes. The majority of our subsidiaries are guarantors under the EXCO Resources Credit Agreement, except those subsidiaries that are jointly held with BG Group and two other subsidiaries that are wholly owned by EXCO Operating Company. The EXCO Resources Credit Agreement permits investments, loans and advances to the unrestricted subsidiaries that are jointly held with BG Group, with certain limitations, and allows us to repurchase up to $200.0 million of our common stock.

Borrowings under the EXCO Resources Credit Agreement are collateralized by first lien mortgages providing a security interest of not less than 80% of the Engineered Value, as defined in the EXCO Resources Credit Agreement, in our oil and natural gas properties covered by the borrowing base. We are permitted to have derivative financial instruments covering no more than 100% of forecasted production from all Proved Reserves (as defined in the agreement) during the first two years of the forthcoming five-year period, 90% of the forecasted production for any month during the third year of the forthcoming five-year period and 85% of the forecasted production 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 its borrowing base available under the EXCO Resources Credit Agreement, and (iii) payment of such dividend is permitted under the indenture governing the 2018 Notes.

The interest rate ranges from LIBOR plus 200 basis points, or bps, to LIBOR plus 300 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 100 bps to ABR plus 200 bps depending upon borrowing base usage.

As of September 30, 2010, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:

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

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• not permit our ratio of consolidated funded indebtedness (as defined in the agreement) to consolidated EBITDAX (as defined in the agreement) to be greater than 3.50 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2010.

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

EXCO Operating credit agreement

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

2011 Notes

On September 15, 2010 we provided notice to the trustee for our 2011 Notes in accordance with the indenture to fully redeem all of the $444.7 million in outstanding notes on October 15, 2010. We used a portion of the proceeds from the issuance of the 2018 Notes for the redemption of the 2011 Notes, including accrued interest of $8.1 million from July 15, 2010 to the redemption date. As of December 31, 2009, $444.7 million in principal was outstanding on the 2011 Notes, with an unamortized premium of $4.0 million.

2018 Notes

On September 15, 2010 we closed an underwritten offering of $750.0 million aggregate principal amount of 7.5% senior unsecured notes maturing on September 15, 2018. We received proceeds of approximately $724.4 million from the offering after deducting an original issue discount, commissions and estimated offering fees and expenses. The net proceeds from the offering were used to redeem the 2011 Notes with the remaining balance of approximately $271.6 million being used to pay a portion of the outstanding balance under the EXCO Resources Credit Agreement. The bonds are guaranteed on a senior unsecured basis by EXCO’s consolidated subsidiaries, which excludes EXCO Caddo Acquisition, LLC, EXCO Water Resources, LLC and all of our jointly-held equity investments with BG Group. 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 September 30, 2010, $750.0 million in principal was outstanding on our 2018 Notes. The unamortized discount on the 2018 Notes at September 30, 2010 was $11.0 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $740.6 million on September 30, 2010.

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 guarantor subsidiaries to:

• incur or guarantee additional debt and issue certain types of preferred stock;

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

• make certain investments;

• create liens on our assets;

• enter into sale/leaseback transactions;

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

• engage in transactions with our affiliates;

• transfer or issue shares of stock of subsidiaries;

• transfer or sell assets; and

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

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11. Dividends

On August 5, 2010, our Board of Directors approved a third quarter 2010 cash dividend of $0.04 per share. The total cash dividend of $8.5 million was paid on September 15, 2010 to holders of record on August 31, 2010. Any future declaration of dividends, as well as the establishment of record and payment dates, is subject to limitations under the EXCO Resources Credit Agreement, our 2018 Notes and the approval of EXCO’s Board of Directors.

12. Income taxes

Each quarter we evaluate our estimated annual effective income tax rate based on current and forecasted business results and enacted tax laws. We apply this tax rate to our ordinary income or loss to calculate our estimated tax liability or benefit. We have accumulated financial operating losses primarily due to ceiling test write-downs to the carrying value of our oil and natural gas properties. For the three and nine months ended September 30, 2010, we utilized $27.4 million and $305.1 million, respectively, of our accumulated valuation allowance. As a result of cumulative financial operating losses, we have recognized net valuation allowances of approximately $372.6 million, as of September 30, 2010, until the realization of future deferred tax benefits are more likely than not to become utilized. The valuation allowance does not impact future utilization of the underlying tax attributes.

13. Operating Segments

We follow FASB ASC Topic 280 for Segment Reporting when reporting operating segments. Prior to the East Texas/North Louisiana midstream joint venture where we sold a 50% interest in most of our East Texas/North Louisiana midstream operations, our reportable segments consisted of exploration and production and midstream. Our exploration and production segment and midstream segment were managed separately because of the nature of their products and services. The exploration and production segment is responsible for acquisition, development and production of oil and natural gas. The midstream segment was responsible for purchasing, gathering, transporting, processing and treating natural gas. We evaluated the performance of our operating segments based on segment profits, which included segment revenues, excluding the gain (loss) on derivative financial instruments, from external and internal customers and segment costs and expenses. Segment profit generally excluded income taxes, interest income, interest expense, unallocated corporate expenses, depreciation and depletion, asset retirement obligations, and gains and losses associated with ceiling test write-downs and asset sales, other income and expense, and income from equity investments.

As a result of the East Texas/North Louisiana midstream joint venture, we reviewed the criteria outlined in FASB ASC 280-10 for Segment Reporting and determined that the midstream assets we retained, made up exclusively of the Vernon Field midstream assets, were not material and therefore, would no longer meet thresholds to be defined as a reportable segment. We also reviewed our equity investment in TGGT and concluded that it also would not be considered a reportable segment. We now account for our interest in TGGT using the equity method (see “Note 14. Equity investments”).

The reportable midstream segment for 2009 is effective from January 1, 2009 through August 13, 2009. The Vernon Field midstream assets operations are included in the exploration and production segment effective August 14, 2009.

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

(in thousands)	Exploration  and production			Midstream		Intercompany eliminations			Consolidated total
For the three months ended September 30, 2010:
Third party revenues	$	130,990		$	—	$	—		$	130,990
Intersegment revenues		—			—		—			—
Total revenues	$	130,990		$	—	$	—		$	130,990
Segment profit	$	94,289		$	—	$	—		$	94,289
For the three months ended September 30, 2009:
Third party revenues	$	125,493		$	5,375	$	—		$	130,868
Intersegment revenues		(4,324	)		8,896		(4,572	)		—
Total revenues	$	121,169		$	14,271	$	(4,572	)	$	130,868
Segment profit	$	73,216		$	4,288	$	—		$	77,504
For the nine months ended September 30, 2010:
Third party revenues	$	380,328		$	—	$	—		$	380,328
Intersegment revenues		—			—		—			—
Total revenues	$	380,328		$	—	$	—		$	380,328
Segment profit	$	261,559		$	—	$	—		$	261,559
For the nine months ended September 30, 2009:
Third party revenues	$	443,953		$	35,330	$	—		$	479,283
Intersegment revenues		(20,356	)		41,148		(20,792	)		—
Total revenues	$	423,597		$	76,478	$	(20,792	)	$	479,283
Segment profit	$	266,180		$	20,106	$	—		$	286,286
As of September 30, 2010:
Capital Expenditures	$	422,655		$	—	$	—		$	422,655
Goodwill	$	218,256		$	—	$	—		$	218,256
Total assets	$	2,912,015		$	—	$	—		$	2,912,015
As of December 31, 2009:
Capital Expenditures	$	458,410		$	53,122	$	—		$	511,532
Goodwill	$	269,656		$	—	$	—		$	269,656
Total assets	$	2,358,894		$	—	$	—		$	2,358,894

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2010			2009			2010			2009
Segment profits	$	94,289		$	77,504		$	261,559		$	286,286
Depreciation, depletion and amortization		(53,687	)		(50,709	)		(137,844	)		(187,683	)
Write-down of oil and natural gas properties		—			—			—			(1,293,579	)
Gain on divestitures and other operating items		(6,257	)		460,641			569,096			452,664
Accretion of discount on asset retirement obligations		(830	)		(1,767	)		(2,920	)		(5,856	)
General and administrative		(24,034	)		(21,647	)		(76,319	)		(64,682	)
Interest expense		(8,440	)		(46,737	)		(33,550	)		(129,760	)
Gain (loss) on derivative financial instruments		56,209			14,518			156,065			204,885
Other income (loss)		67			32			184			67
Equity income (loss)		6,675			(426	)		12,054			(426	)
Income (loss) before income taxes	$	63,992		$	431,409		$	748,325		$	(738,084	)

14. Equity investments

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

In conjunction with the Appalachia JV, we own a 50% interest in OPCO, which operates the properties, subject to oversight from a management board having equal representation from EXCO and BG Group. At the date of formation, our 50% equity interest in OPCO exceeded the book value of our investment by $4.1 million, which represented the difference in the historical basis of our contributed assets and the 50% interest in the fair value sold to BG Group. The $4.1 million basis difference is being amortized over the estimated amortized life of OPCO’s unproved properties.

In addition, certain midstream assets owned by EXCO in Appalachia were transferred to a newly formed, jointly owned entity, Appalachia Midstream, LLC, through which EXCO and BG Group will pursue the construction and expansion of gathering systems for anticipated future production from the Marcellus Shale. Our investment in Appalachia Midstream, LLC represents the net book value, which approximates fair value, of the assets we contributed, less the 50% interest we sold to BG Group upon closing the Appalachia JV.

Our third equity method investment is our 50% ownership in TGGT, which holds most of our midstream assets in East Texas and North Louisiana. The following tables present summarized combined financial information of our equity investments and a reconciliation of our investment to our proportionate 50% interest.

20

(in thousands)						As of September 30, 2010			As of December 31, 2009
Assets
Total current assets						$	128,788		$	54,818
Property and equipment, net							758,587			509,501
Other assets							950			—
Total assets						$	888,325		$	564,319
Liabilities and members' equity
Total current liabilities						$	131,628		$	40,915
Total long-term liabilities							11,683			2,393
Members’ equity:
Total members’ equity							745,014			521,011
Total liabilities and members’ equity						$	888,325		$	564,319
	Three months ended September 30, 2010		For the 48 day  period from August 14, 2009 to September 30, 2009			Nine months ended September 30, 2010			For the 48 day  period from August 14, 2009 to September 30, 2009
Revenues
Oil and natural gas	$	69	$	—		$	94		$	—
Midstream		39,133		9,679			114,485			9,679
Total revenues		39,202		9,679			114,579			9,679
Costs and expenses:
Oil and natural gas production		120		—			162			—
Midstream operating		18,916		8,279			69,800			8,279
Other expenses		2,905		728			10,483			728
Depreciation, depletion and amortization		4,971		1,524			12,651			1,524
Total costs and expenses		26,912		10,531			93,096			10,531
Income before income taxes		12,290		(852	)		21,483			(852	)
Income tax expense		87		—			246			—
Net income (loss)	$	12,203	$	(852	)	$	21,237		$	(852	)
EXCO’s share of equity income (loss) before amortization	$	6,102	$	(426	)	$	10,619		$	(426	)
Amortization of the difference in the historical basis of our contribution		573		—			1,435			—
EXCO’s share of equity income (loss) after amortization	$	6,675	$	(426	)	$	12,054		$	(426	)
(in thousands)						As of September 30, 2010			As of December 31, 2009
Equity investments						$	326,317		$	216,987
Basis adjustment (1)							48,242			44,135
Cumulative amortization of basis adjustment (2)							(2,052	)		(617	)
EXCO’s 50% interest in September 30, 2010 equity investments						$	372,507		$	260,505

(1) Our equity in TGGT and OPCO at inception exceeded the book value of our investments by an aggregate of $48.2 million, comprised of a $59.6 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 $59.6 million basis difference is being amortized over the estimated life of the associated assets.

15. Share Repurchase

        On July 19, 2010, we announced a share repurchase program which authorizes us to purchase up to $200.0 million of our common stock. Any repurchases will be made in the open market, in privately negotiated transactions or in structured share repurchase programs, and may be made from time to time and in one or more large repurchases. The program will be conducted in compliance with the Securities and Exchange Commission’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, 2010, we have repurchased a total of 539,221 shares for $7.5 million at an average price of $13.87 per share.

16. Subsequent events

        On October 6, 2010, the lenders under the EXCO Resources Credit Agreement completed their regular semi-annual redetermination of our borrowing base, resulting in a borrowing base of $1.0 billion following the offering of the 2018 Notes. The next redetermination of the borrowing base is scheduled to occur on April 1, 2011.

        On November 1, 2010, we announced that our Chairman and Chief Executive Officer, Douglas H. Miller, had submitted to our Board of Directors a proposal to purchase all of the outstanding shares of our common stock for at a cash purchase price of $20.50 per share. Our Board of Directors intends to establish a special committee of the Board comprised of independent directors to consider, among other things, the proposal. There can be no assurance that any definitive offer will be made or accepted, that any agreement will be executed or that any transaction will be consummated.

21

17. Condensed consolidating financial statements

Effective April 30, 2010, the EXCO Operating credit agreement was consolidated into the EXCO Resources Credit Agreement, with certain non-guarantor subsidiaries, including EXCO Operating, which owns all of our East Texas/North Louisiana assets, becoming restricted subsidiaries and guarantor subsidiaries under our 2011 Notes. The accompanying condensed consolidating financial statements are presented as if the previous non-guarantor subsidiaries were guarantor subsidiaries for each of the periods presented.

As of September 30, 2010, all of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement and the indenture governing the 2018 Notes with the exception of those equity investments that are jointly held with BG Group and two subsidiaries that are wholly owned by EXCO Operating Company. 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 September 30, 2010 and the nine months ended September 30, 2010:

• Our equity method investment in OPCO was a negative $4.1 million, consisting of net liabilities transferred to the joint venture on June 1, 2010 and $41,000 of equity method losses.

• Our interests in jointly held entities with BG Group, with the exception of OPCO, represented $330.4 million of equity method investments, or 11.3% of our total assets and contributed $12.1 million of equity method income.

• Our non-guarantor, unrestricted subsidiaries that are wholly owned represented approximately 1.2% of our total revenues, 2.9% of our total assets and $11.5 million of liabilities, including trade payables, but excluding intercompany liabilities.

Set forth below are condensed consolidating financial statements of EXCO, the guarantor subsidiaries and the non-guarantor subsidiaries. The 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.

22

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

(Unaudited)

September 30, 2010

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	80,568		$	(29,444	)	$	—		$	—		$	51,124
Restricted cash		—			100,249			—			—			100,249
Other current assets		86,906			250,580			853			—			338,339
Total current assets		167,474			321,385			853			—			489,712
Equity Investment		—			—			326,317			—			326,317
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		41,030			556,023			36,220			—			633,273
Proved developed and undeveloped oil and natural gas properties		365,964			1,842,722			35,866			—			2,244,552
Accumulated depletion		(292,191	)		(963,845	)		(1,642	)		—			(1,257,678	)
Oil and natural gas properties, net		114,803			1,434,900			70,444			—			1,620,147
Gas gathering, office and field equipment, net		26,721			133,976			12,607			—			173,304
Investments in and advances to affiliates		1,011,600			—			—			(1,011,600	)		—
Deferred financing costs, net		32,081			—			—			—			32,081
Derivative financial instruments		27,411			13,553			—			—			40,964
Goodwill		38,100			180,156			—			—			218,256
Other assets		3			11,231			—			—			11,234
Total assets	$	1,418,193		$	2,095,201		$	410,221		$	(1,011,600	)	$	2,912,015
Liabilities and shareholders’ equity
Current liabilities	$	45,175		$	198,193		$	11,443		$	—			254,811
Long-term debt, net of current maturities		993,417			—			—			—			993,417
Deferred income taxes		—			—			—			—			—
Other liabilities		8,057			55,813			46			—			63,916
Payable to parent		(1,228,327	)		1,210,536			17,791			—			—
Total shareholders’ equity		1,599,871			630,659			380,941			(1,011,600	)		1,599,871
Total liabilities and shareholders’ equity	$	1,418,193		$	2,095,201		$	410,221		$	(1,011,600	)	$	2,912,015

23

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2009

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	47,412		$	20,995		$	—	$	—		$	68,407
Restricted cash		—			58,909			—		—			58,909
Other current assets		69,449			204,880			443		—			274,772
Total current assets		116,861			284,784			443		—			402,088
Equity investment in TGGT Holdings, LLC		—			—			216,987		—			216,987
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		54,570			394,313			43,999		—			492,882
Proved developed and undeveloped oil and natural gas properties		328,135			1,539,252			8,362		—			1,875,749
Accumulated depletion		(274,275	)		(858,329	)		—		—			(1,132,604	)
Oil and natural gas properties, net		108,430			1,075,236			52,361		—			1,236,027
Gas gathering, office and field equipment, net		8,175			181,261			—		—			189,436
Investments in and advances to affiliates		198,661			—			—		(198,661	)		—
Deferred financing costs, net		3,166			4,436			—		—			7,602
Derivative financial instruments		31,312			3,365			—		—			34,677
Goodwill		38,100			231,556			—		—			269,656
Other assets		3			2,418			—		—			2,421
Total assets	$	504,708		$	1,783,056		$	269,791	$	(198,661	)	$	2,358,894
Liabilities and shareholders’ equity
Current liabilities	$	39,917		$	172,795		$	202	$	—		$	212,914
Long-term debt		530,199			666,078			—		—			1,196,277
Deferred income taxes		—			—			—		—			—
Other liabilities		5,998			84,117			—		—			90,115
Payable to parent		(930,994	)		930,994			—		—			—
Total shareholders’ equity		859,588			(70,928	)		269,589		(198,661	)		859,588
Total liabilities and shareholders’ equity	$	504,708		$	1,783,056		$	269,791	$	(198,661	)	$	2,358,894

24

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

25

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the three months ended September 30, 2009

(in thousands)	Resources			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	37,260		$	88,233		$	—		$	—		$	125,493
Midstream		—			5,375			—			—			5,375
Total revenues		37,260			93,608			—			—			130,868
Costs and expenses:
Oil and natural gas production		10,992			32,034			—			—			43,026
Midstream operating		—			5,411			—			—			5,411
Gathering and transportation		—			4,927			—			—			4,927
Depreciation, depletion and amortization		12,819			37,890			—			—			50,709
Accretion of discount on asset retirement obligations		422			1,345			—			—			1,767
General and administrative		6,472			15,175			—			—			21,647
Gain on divestitures and other operating items		(99,160	)		(361,481	)		—			—			(460,641	)
Total costs and expenses		(68,455	)		(264,699	)		—			—			(333,154	)
Operating income (loss)		105,715			358,307			—			—			464,022
Other income (expense):
Interest expense		(17,025	)		(29,712	)		—			—			(46,737	)
Gain on derivative financial instruments		7,053			7,465			—			—			14,518
Other income (expense)		6,230			(6,198	)		—			—			32
Equity method income		—			—			(426	)		—			(426	)
Equity in earnings of subsidiaries		329,436			—			—			(329,436	)		—
Total other income (expense)		325,694			(28,445	)		(426	)		(329,436	)		(32,613	)
Income (loss) before income taxes		431,409			329,862			(426	)		(329,436	)		431,409
Income tax expense		(1,921	)		—			—			—			(1,921	)
Net income (loss)	$	433,330		$	329,862		$	(426	)	$	(329,436	)	$	433,330

26

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2010

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

27

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(Unaudited)

For the nine months ended September 30, 2009

				Guarantor			Non-Guarantor
(in thousands)	Resources			Subsidiaries			Subsidiaries			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	116,885		$	327,068		$	—		$	—	$	443,953
Midstream		—			35,330			—					35,330
Total revenues		116,885			362,398			—			—		479,283
Costs and expenses:
Oil and natural gas production		38,367			106,171			—			—		144,538
Midstream operating		—			35,580			—			—		35,580
Gathering and transportation		87			12,792			—			—		12,879
Depreciation, depletion and amortization		43,782			143,901			—			—		187,683
Write-down of oil and natural gas properties		279,632			1,013,947			—					1,293,579
Accretion of discount on asset retirement obligations		1,444			4,412			—			—		5,856
General and administrative		12,186			52,496			—			—		64,682
Gain on divestitures and other operating items		(99,930	)		(352,734	)		—			—		(452,664	)
Total costs and expenses		275,568			1,016,565			—			—		1,292,133
Operating income (loss)		(158,683	)		(654,167	)		—			—		(812,850	)
Other income (expense):
Interest expense		(45,161	)		(84,599	)		—			—		(129,760	)
Gain on derivative financial instruments		78,059			126,826			—			—		204,885
Other income (expense)		18,628			(18,561	)		—			—		67
Equity method income		—			—			(426	)		—		(426	)
Equity in earnings of subsidiaries		(630,927	)		—			—			630,927		—
Total other income (expense)		(579,401	)		23,666			(426	)		630,927		74,766
Income (loss) before income taxes		(738,084	)		(630,501	)		(426	)		630,927		(738,084	)
Income tax expense		189			—			—			—		189
Net income (loss)	$	(738,273	)	$	(630,501	)	$	(426	)	$	630,927	$	(738,273	)

28

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2010

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

29

EXCO RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(Unaudited)

For the nine months ended September 30, 2009

				Guarantor			Non-Guarantor
(in thousands)	Resources			Subsidiaries			Subsidiaries		Eliminations		Consolidated
Operating Activities:
Net cash provided by operating activities	$	165,582		$	184,275		$	—	$	—	$	349,857
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(40,053	)		(416,580	)		—		—		(456,633	)
Restricted Cash		—			(69,983	)		—		—		(69,983	)
Investment in equity investments		—			(47,500	)		—		—		(47,500	)
Deposits on pending property divestitures		—			14,500			—		—		14,500
Proceeds from dispositions		262,808			1,146,570			—		—		1,409,378
Advances/investments with affiliates		(113,107	)		113,107			—		—		—
Net cash provided by (used in) investing activities		109,648			740,114			—		—		849,762
Financing Activities:
Borrowings under credit agreements		14,979			37,970			—		—		52,949
Repayments under credit agreements		(312,500	)		(1,068,240	)		—		—		(1,380,740	)
Settlement of derivative financial instruments with a financing element		45,859			95,923			—		—		141,782
Proceeds from issuance of common stock, net		5,400			—			—		—		5,400
Deferred financing costs and other		(5,386	)		(15,082	)		—		—		(20,468	)
Net cash used in financing activities		(251,648	)		(949,429	)		—		—		(1,201,077	)
Net increase (decrease) in cash		23,582			(25,040	)		—		—		(1,458	)
Cash at beginning of period		8,617			48,522			—		—		57,139
Cash at end of period	$	32,199		$	23,482		$	—	$	—	$	55,681

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context requires otherwise, references to “EXCO,” “EXCO Resources,” “Company,” “we,” “us,” and “our” are to EXCO Resources, Inc. and its consolidated subsidiaries.

Forward-looking statements

This quarterly report contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These forward-looking statements relate to, among other things, the following:

• our future financial and operating performance and results;

• our business strategy;

• market prices;

• our future derivative financial instrument activities; and

• our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

We use the words “may,” “expect,” “anticipate,” “estimate,” “believe,” “continue,” “intend,” “plan,” “budget” and other similar words to identify forward-looking statements. You should read statements that contain these words carefully because they discuss future expectations, contain projections of results of operations or of our financial condition and/or state other “forward-looking” information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this quarterly report, including, but not limited to:

• fluctuations in prices of oil and natural gas;

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

• future capital requirements and availability of financing;

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

• estimates of reserves and economic assumptions;

• geological concentration of our reserves;

• risks associated with drilling and operating wells;

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

• risks associated with the operation of natural gas pipelines and gathering systems;

• discovery, acquisition, development and replacement of oil and natural gas reserves;

• cash flow and liquidity;

• timing and amount of future production of oil and natural gas;

• availability of drilling and production equipment;

• marketing of oil and natural gas;

• developments in oil-producing and natural gas-producing countries;

• title to our properties;

• litigation;

• competition;

• general economic conditions, including costs associated with drilling and operations of our properties;

• environmental or other governmental regulations, including legislation to reduce emissions of greenhouse gases, legislation of derivative financial instruments, regulation of hydraulic fracture stimulation and elimination of income tax incentives available to our industry;

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• receipt and collectability of amounts owed to us by purchasers of our production and counterparties to our derivative financial instruments;

• decisions whether or not to enter into derivative financial instruments;

• potential acts of terrorism;

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

• fluctuations in interest rates; and

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

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this quarterly report, and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2009.

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 affect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and ability to fund our operations. Lower oil and natural gas prices may also reduce the amount of oil and natural gas we can produce economically. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

Overview

We are an independent oil and natural gas company engaged in the exploration, exploitation, development and production of onshore North American 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, respectively.

In 2009, we were primarily focused on increasing our drilling activities in the Haynesville shale, deleveraging our balance sheet and executing our divestiture program to allow for increased attention on exploitation of our shale play assets. Beginning in 2009, we closed several significant divestiture transactions of oil and natural gas properties, undeveloped acreage and midstream assets. In addition, during 2009 and 2010, we sold 50% of certain oil and natural gas properties located in East Texas, North Louisiana and Appalachia to affiliates of BG Group plc, or BG Group, and intend to jointly develop these assets with BG Group. We also entered into two midstream joint ventures with BG Group; TGGT Holdings, LLC in East Texas and North Louisiana, or TGGT, and Appalachia Midstream LLC, or Appalachia Midstream. The closing of our upstream and midstream joint venture transactions with BG Group, coupled with our other successful divestitures, enabled us to accelerate our horizontal drilling program in East Texas/North Louisiana, strategically add to our acreage position and reduce our debt. The impact of our 2009 divestitures and joint ventures with BG Group resulted in significant reductions to our Proved Reserves, production volumes, revenue and operating expenses. While the reductions will have a near-term impact on our results of operations, we believe the benefits from the liquidity provided by these transactions along with capital expenditure reductions arising from a carried interest equal to 75% of our drilling and completion costs on horizontal wells, will allow us to accelerate development of our reserves and resources, including our shale development, and will more than compensate for these reductions.

Our primary strategy is to 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. Acquisitions are likely to be focused on supplementing our shale assets. We will continue to develop certain vertical drilling opportunities as economic conditions permit. Funds generated from our mature, low-cost fields are used as a source of cash flows to develop our shale resources. We expect to continue to grow by leveraging our management and technical teams’ experience, developing our shale resource plays through our joint ventures, exploiting our multi-year inventory of development drilling locations and accumulating undeveloped acreage in shale areas.

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The joint ventures with BG Group in East Texas/North Louisiana, or the East Texas/North Louisiana JV, and Appalachia, or the Appalachia JV, provided us with substantial liquidity to reduce our outstanding debt, accelerate our shale development and midstream projects. In addition to the closing cash received from those joint ventures of approximately $1.8 billion, we received $550.0 million of carried drilling costs, which reduces capital costs in our shale plays during early development of the plays.

Our credit agreement, as amended on April 30, 2010, or the EXCO Resources Credit Agreement, has a borrowing base of $1.0 billion, of which $294.4 million was drawn as of October 29, 2010. Available borrowing capacity was $690.3 million as of October 29, 2010. We also have $750.0 million of 7.5% senior notes due September 15, 2018, or the 2018 Notes.

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Our net budgeted capital expenditures for 2010, including funds received from BG Group for acreage reimbursements, total $496.8 million. We also expect to contribute a total of $143.5 million to our midstream investments for 2010. Our East Texas/North Louisiana JV capital expenditures are favorably impacted by a $400.0 million drilling carry equal to 75% of our share of drilling and completion costs within the East Texas/North Louisiana JV until the carry amount is satisfied, or the East Texas/North Louisiana Carry. During the first nine months of 2010, we spent $250.8 million in East Texas/North Louisiana, $190.0 million of which was in the East Texas/North Louisiana JV. As of September 30, 2010, the remaining balance of the East Texas/North Louisiana Carry was approximately $134.2 million, which we anticipate will be fully utilized by the first quarter of 2011. In Appalachia we spent $90.4 million during the first nine months of 2010 and our remaining planned capital expenditures are expected to total $22.2 million. Similar to the East Texas/North Louisiana JV, our Appalachia JV capital expenditures will be favorably impacted by a $150.0 million carry equal to approximately 75% of our share of deep drilling and completion costs within our joint venture area until the carry amount is satisfied, or the Appalachia Carry. As of September 30, 2010, the remaining balance of the Appalachia Carry was approximately $147.1 million.

For the three and nine months ended September 30, 2010, we made $31.5 million and $100.0 million, respectively, in equity contributions to TGGT. For the remainder of 2010, we expect to fund additional equity contributions to TGGT of $28.5 million primarily to develop the midstream infrastructure in the Haynesville shale. TGGT is currently evaluating the establishment of a credit facility to fund future capital expenditures.

For the three months ended September 30, 2010, we produced 29.5 Bcfe of oil and natural gas. Of the amount produced, 26.1 Bcfe were produced in our East Texas/North Louisiana division, 1.6 Bcfe were produced in our Appalachia division and 1.8 Bcfe were produced in our Permian division.

For the nine months ended September 30, 2010, we produced 79.8 Bcfe of oil and natural gas. Of the amount produced, 66.9 Bcfe were produced in our East Texas/North Louisiana division, 7.6 Bcfe were produced in our Appalachia division and 5.3 Bcfe were produced in our Permian division.

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 overcome this natural decline by drilling to identify and develop additional reserves and adding additional reserves through acquisitions.

Critical accounting policies

We consider accounting policies related to our estimates of assets and liabilities acquired in acquisitions, proved reserves, accounting for derivatives, business combinations, share-based payments, accounting for oil and natural gas properties, goodwill, asset retirement obligations and accounting for income taxes as critical accounting policies. The policies include significant estimates made by management using information available at the time the estimates are made. However, these estimates could change materially if different information or assumptions were used. These policies are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2009.

Recent Events

On November 1, 2010, we announced that our Chairman and Chief Executive Officer, Douglas H. Miller, had submitted to our Board of Directors a proposal to purchase all of the outstanding shares of our common stock for at a cash purchase price of $20.50 per share. Our Board of Directors intends to establish a special committee of the Board comprised of independent directors to consider, among other things, the proposal. There can be no assurance that any definitive offer will be made or accepted, that any agreement will be executed or that any transaction will be consummated.

Recent accounting pronouncements

On January 21, 2010, the Financial Accounting Standards Board, or the FASB, issued Accounting Standards Update, or ASU, No. 2010-06—Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed. Fair value measurements using significant unobservable inputs should be presented on a gross basis and the fair value measurement disclosure should be reported for each class of asset and liability. Disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements will be required for fair value measurements that fall in either Level 2 or 3. The update is effective for interim and annual reporting periods beginning after December 15, 2009.

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Our results of operations

A summary of key financial data for the three and nine months ended September 30, 2010 and 2009 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)	2010		2009			2010-2009			2010			2009			2010-2009
Production:
Oil (Mbbls)		178		355			(177	)		505			1,367			(862	)
Natural gas (Mmcf)		28,408		29,806			(1,398	)		76,784			96,598			(19,814	)
Total production (Mmcfe) (1)		29,476		31,936			(2,460	)		79,814			104,800			(24,986	)
Oil and natural gas revenues before derivative financial instrument activities:
Oil.	$	12,968	$	22,678		$	(9,710	)	$	37,437		$	69,571		$	(32,134	)
Natural gas		118,022		102,815			15,207			342,891			374,382			(31,491	)
Total oil and natural gas	$	130,990	$	125,493		$	5,497		$	380,328		$	443,953		$	(63,625	)
Oil and natural gas derivative financial instruments:
Cash settlements (payments) on derivative financial instruments	$	43,075	$	113,563		$	(70,488	)	$	166,660		$	354,131		$	(187,471	)
Non-cash change in fair value of derivative financial instruments		13,134		(99,045	)		112,179			(10,595	)		(149,246	)		138,651
Total derivative financial instrument activities	$	56,209	$	14,518		$	41,691		$	156,065		$	204,885		$	(48,820	)
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	72.85	$	63.88		$	8.97		$	74.13		$	50.89		$	23.24
Natural gas (per Mcf)		4.15		3.45			0.70			4.47			3.88			0.59
Natural gas equivalent (per Mcfe)		4.44		3.93			0.51			4.77			4.24			0.53
Costs and expenses:
Oil and natural gas operating costs (2)	$	22,125	$	32,374		$	(10,249	)	$	63,821		$	112,092		$	(48,271	)
Production and ad valorem taxes		3,015		10,652			(7,637	)		19,401			32,446			(13,045	)
Gathering and transportation		11,561		4,927			6,634			35,547			12,879			22,668
Depletion		49,933		44,735			5,198			125,075			167,812			(42,737	)
Depreciation and amortization		3,754		5,974			(2,220	)		12,769			19,871			(7,102	)
General and administrative (3)		24,034		21,647			2,387			76,319			64,682			11,637
Interest expense, net, including impacts of interest rate swaps		8,440		46,737			(38,297	)		33,550			129,760			(96,210	)
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.75	$	1.01		$	(0.26	)	$	0.80		$	1.07		$	(0.27	)
Production and ad valorem taxes		0.10		0.33			(0.23	)		0.24			0.31			(0.07	)
Gathering and transportation		0.39		0.15			0.24			0.45			0.12			0.33
Depletion		1.69		1.40			0.29			1.57			1.60			(0.03	)
Depreciation and amortization		0.13		0.19			(0.06	)		0.16			0.19			(0.03	)
General and administrative		0.82		0.68			0.14			0.96			0.62			0.34
Net income (loss)	$	64,896	$	433,330		$	(368,434	)	$	744,777		$	(738,273	)	$	1,483,050

(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 $0.2 million, $0.8 million, $0.6 million and $2.0 million for the three and nine months ended September 30, 2010 and 2009, respectively.

(3) Share-based compensation included in general and administrative expenses is $2.2 million, $10.0 million, $2.8 million and $7.9 million for the three and nine months ended September 30, 2010 and 2009, respectively.

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The following is a discussion of our financial condition and results of operations for the three and nine months ended September 30, 2010 and 2009.

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

• the East Texas/North Louisiana JV;

• the Appalachia JV;

• 2009 divestitures;

• 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;

• changes in Proved Reserves and production volumes, including the impact of SEC Release No. 33-8995 effective December 31, 2009, and their impact on depletion;

• a ceiling test write-down in the first quarter of 2009; and

• the equity method of accounting for our investments.

General

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

• the level of domestic production and economic activity, particularly the worldwide economic slowdown which continues to put downward pressure on natural gas prices and demand;

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

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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. Further, significant declines in the prices of oil or natural gas may have a material adverse effect on our business and on our financial condition.

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

Summary

For the three months ended September 30, 2010, we reported net income of $64.9 million, compared to net income of $433.3 million for the three months ended September 30, 2009. For the nine months ended September 30, 2010, we reported net income of $744.8 million, compared to a net loss of $738.3 million for the nine months ended September 30, 2009.

On June 1, 2010, we closed the Appalachia JV, which resulted in the sale of a 50% undivided interest in substantially all of our Appalachian oil and natural gas proved and unproved properties for cash consideration of approximately $835.2 million, subject to final closing adjustments, plus a $150.0 million deep drilling carry. In connection with the Appalachia JV, we recorded a pretax gain of $575.0 million during the second quarter of 2010. During 2009, we recorded a first quarter $1.3 billion non-cash ceiling test write-down, completed a divestiture program, or the 2009 Divestitures, and entered into the East Texas/North Louisiana JV and TGGT. Proceeds from the 2009 Divestitures and joint venture transactions were approximately $2.1 billion plus the $400.0 million East Texas/North Louisiana Carry, resulting in decreases in our full cost pool, gathering assets, operating assets and liabilities, and gains totaling approximately $691.9 million. As a result, when comparing the first nine months and third quarter of 2010 to the first nine months and third quarter of 2009, there are significant declines in our production of oil and natural gas, revenues and operating costs. The aforementioned transactions will impact comparability of our 2010 and 2009 results of operations throughout 2010. Accordingly, we are presenting certain pro forma comparisons to facilitate comparison of operating data between 2010 and 2009.

Upon closing TGGT, we adopted the equity method of accounting for our investment in TGGT and discontinued reporting our midstream operations as a separate business segment. Results of operations from our Vernon gathering system, which was not part of TGGT, are now recorded net in “Gathering and transportation” on our Condensed Consolidated Statements of Operations.

Oil and natural gas production, revenues, and prices

Total equivalent production volumes were 29.5 Bcfe for the three months ended September 30, 2010, a 7.7% decrease from the prior year’s comparable period production of 31.9 Bcfe, and 79.8 Bcfe for the nine months ended September 30, 2010, a 23.8% decrease from the prior year’s comparable period production of 104.8 Bcfe. Because these declines result primarily from the 2009 divestitures, the East Texas/North Louisiana JV and the Appalachia JV, as discussed above, management believes that analyzing the production on a pro forma basis, assuming the divestitures and joint venture transactions had occurred on January 1, 2009, provides a more meaningful analysis of the on-going production activity.

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	Three months ended September 30,
	2010							2009							Quarter to quarter change
(in Mmcfe)	Actual production		Pro forma adjustment (1)			Pro forma production		Actual production		Pro forma adjustment (2)			Pro forma production		Actual production			Pro forma production
Producing region:
East Texas/North Louisiana		26,045		—			26,045		20,573		(3,646	)		16,927		5,472			9,118
Appalachia		1,608		—			1,608		4,743		(3,099	)		1,644		(3,135	)		(36	)
Permian and other		1,823		—			1,823		1,898		(80	)		1,818		(75	)		5
Mid-Continent		—		—			—		4,722		(4,722	)		—		(4,722	)		—
Total		29,476		—			29,476		31,936		(11,547	)		20,389		(2,460	)		9,087
	Nine months ended September 30,
	2010							2009							Period to period change
(in Mmcfe)	Actual production		Pro forma adjustment (1)			Pro forma production		Actual production		Pro forma adjustment (2)			Pro forma production		Actual production			Pro forma production
Producing region:
East Texas/North Louisiana		66,895		—			66,895		66,530		(18,865	)		47,665		365			19,230
Appalachia		7,618		(2,707	)		4,911		14,893		(9,643	)		5,250		(7,275	)		(339	)
Permian and other		5,301		—			5,301		7,153		(968	)		6,185		(1,852	)		(884	)
Mid-Continent		—		—			—		16,224		(16,224	)		—		(16,224	)		—
Total		79,814		(2,707	)		77,107		104,800		(45,700	)		59,100		(24,986	)		18,007

(1) The pro forma adjustments reduce production volumes attributable to the properties affected by the Appalachia JV as if the sale had occurred on January 1, 2010.

(2) The pro forma adjustments reduce production volumes attributable to properties sold in 2009 and properties affected by both the East Texas/North Louisiana JV and the Appalachia JV as if these sales had occurred on January 1, 2009.

On a pro forma basis, production in our East Texas/North Louisiana region for the three and nine months ended September 30, 2010 increased by 9.1 Bcfe and 19.2 Bcfe, or 53.9% and 40.3%, respectively, from the same periods in the prior year. These increases were a result of the continued successful development of our Haynesville shale, which resulted in a production increase of 12.3 Bcfe for the three months ended September 30, 2010 and a production increase of 29.8 Bcfe for the nine months ended September 30, 2010, when compared to the same periods in the prior year. These increases were offset by production declines of 1.4 Bcfe in our Cotton Valley area and 1.8 Bcfe in our Vernon Field for the three months ended September 30, 2010 and declines of 3.6 Bcfe in our Cotton Valley area and 7.0 Bcfe in our Vernon Field for the nine months ended September 30, 2010, when compared to the same periods in the prior year. These declines are primarily the result of the suspension of vertical drilling operations in 2009 and normal production declines. The Appalachia and Permian divisions also experienced production declines due primarily to suspension of certain drilling programs in both areas during 2009. We re-initiated drilling operations in our Permian Basin region in 2010 and have recently seen increases in our production.

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The following table presents our revenues, production and prices by major producing areas, based on historical data, for the three and nine months ended September 30, 2010 and 2009:

	Three months ended September 30,
	2010						2009						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		26,045	$	106,649	$	4.09		20,573	$	69,252	$	3.37		5,472		$	37,397		$	0.72
Appalachia		1,608		7,316		4.55		4,743		18,981		4.00		(3,135	)		(11,665	)		0.55
Permian and other		1,823		17,025		9.34		1,898		14,430		7.60		(75	)		2,595			1.74
Mid-Continent		—		—		—		4,722		22,830		4.83		(4,722	)		(22,830	)		(4.83	)
Total		29,476	$	130,990		4.44		31,936	$	125,493		3.93		(2,460	)	$	5,497			0.51
	Nine months ended September 30,
	2010						2009						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		66,895	$	290,998	$	4.35		66,530	$	256,128	$	3.85		365		$	34,870		$	0.50
Appalachia		7,618		38,582		5.06		14,893		70,940		4.76		(7,275	)		(32,358	)		0.30
Permian and other		5,301		50,748		9.57		7,153		43,257		6.05		(1,852	)		7,491			3.52
Mid-Continent		—		—		—		16,224		73,628		4.54		(16,224	)		(73,628	)		(4.54	)
Total		79,814	$	380,328		4.77		104,800	$	443,953		4.24		(24,986	)	$	(63,625	)		0.53

For the three months ended September 30, 2010, oil and natural gas revenues were $131.0 million, a 4.4% increase from the three months ended September 30, 2009 oil and natural gas revenues of $125.5 million. The increase in revenues is primarily a result of the overall increases in average prices and increased production in our Haynesville operations, offset in part by the 2009 Divestitures, the East Texas/North Louisiana JV and the Appalachia JV. The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased from $63.88 per Bbl for the three months ended September 30, 2009 to $72.85 per Bbl for the three months ended September 30, 2010, or 14.0%,. The average natural gas sales price, excluding the impact of derivative financial instruments, was $4.15 per Mcf, an increase of 20.3% for the three months ended September 30, 2010 compared with $3.45 per Mcf for the three months ended September 30, 2009.

For the nine months ended September 30, 2010, total oil and natural gas revenues were $380.3 million, a 14.3% decrease from the nine months ended September 30, 2009 total oil and natural gas revenues of $444.0 million. The decline in revenue is primarily a result of the 2009 Divestitures and the East Texas/North Louisiana JV, partially offset by increases in the prices received. The average sales price of oil per Bbl, excluding the impact of derivative financial instruments, increased from $50.89 per Bbl for the nine months ended September 30, 2009 to $74.13 per Bbl for the nine months ended September 30, 2010, or 45.7%. The average natural gas sales price, excluding the impact of derivative financial instruments, was $4.47 per Mcf, an increase of 15.2% for the nine months ended September 30, 2010 compared with $3.88 per Mcf for the nine months ended September 30, 2009.

The price we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, estimates of oil and natural gas in storage, weather and other seasonal conditions, including hurricanes and tropical storms. Market conditions involving over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect the volatility to continue in the future. Changes in oil and natural gas prices have a significant impact on our oil and natural gas revenues, cash flows, quantities of estimated Proved Reserves and related liquidity. Assuming we maintain our nine months ended September 30, 2010 average production levels for the remainder of the year, a change of $0.10 per Mcf of natural gas sold would result in an annual increase or decrease in revenues of approximately $10.2 million and a change of $1.00 per Bbl of oil sold would result in an annual increase or decrease in revenues and cash flow of approximately $0.7 million, without considering the effects of derivative financial instruments. In addition, our production volumes are impacted by shut-in volumes of natural gas due to operational requirements associated with fracture stimulation on near-by horizontal wells, seasonal supply and demand conditions from end users and general maintenance and repairs to our wells. While these shut-in volumes are typically for short periods of time, they may have impacts to our revenues, cash flows and results of operations.

39

Oil and natural gas operating costs

Our oil and natural gas operating costs for the three and nine months ended September 30, 2010 were $22.1 million and $63.8 million, respectively, and represent decreases of $10.3 million, or 31.7%, and $48.3 million, or 43.1%, respectively, from comparable periods in 2009, again primarily due to the 2009 Divestitures and joint venture transactions. While the total dollar value decreased, management believes that analyses on a per Mcfe basis provide a more meaningful measure than the absolute dollar variances since the 2009 Divestitures and East Texas/North Louisiana JV in 2009 were significant.

As shown in the table below, on a per Mcfe basis, oil and natural gas operating expenses for the three months ended September 30, 2010 decreased $0.26 per Mcfe from the same period in 2009, with lease operating expenses representing $0.29 per Mcfe of the decrease, offset by a $0.03 per Mcfe increase in workovers and other. The net decrease in Mcfe in East Texas/North Louisiana is a result of increased production in our Haynesville shale, which has a relatively low lease operating rate per Mcfe, and is partially offset by costs in our Vernon Field and Cotton Valley area, which have a higher lease operating expense rate per Mcfe. The decreases in lease operating expenses are offset in part by increased workover expenses particularly in our Vernon Field. The increased workover activity in our Vernon Field has mitigated production declines in this important field, which represented approximately 22.4% of our total production for the three months ended September 30, 2010. Increases in both Appalachia and Permian are a result of production declines associated with suspended drilling operations.

	Three months ended September 30,
	2010						2009						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	$	13,026	$	3,755	$	16,781	$	14,833	$	2,705	$	17,538	$	(1,807	)	$	1,050		$	(757	)
Appalachia		2,804		—		2,804		7,127		317		7,444		(4,323	)		(317	)		(4,640	)
Permian and other		2,289		251		2,540		2,144		368		2,512		145			(117	)		28
Mid-Continent								4,551		329		4,880		(4,551	)		(329	)		(4,880	)
Total	$	18,119	$	4,006	$	22,125	$	28,655	$	3,719	$	32,374	$	(10,536	)	$	287		$	(10,249	)
	Three months ended September 30,
	2010						2009						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	$	0.50	$	0.14	$	0.64	$	0.72	$	0.13	$	0.85	$	(0.22	)	$	0.01		$	(0.21	)
Appalachia		1.74		—		1.74		1.50		0.07		1.57		0.24			(0.07	)		0.17
Permian and other		1.25		0.14		1.39		1.13		0.19		1.32		0.12			(0.05	)		0.07
Mid-Continent								0.96		0.07		1.03		(0.96	)		(0.07	)		(1.03	)
Operating costs per Mcfe		0.61		0.14		0.75		0.90		0.11		1.01		(0.29	)		0.03			(0.26	)

40

As shown in the table below, on a per Mcfe basis, oil and natural gas operating expenses for the nine months ended September 30, 2010 decreased $0.27 per Mcfe from the same period in 2009, with lease operating expenses representing $0.28 per Mcfe of the decrease, offset by a $0.01 per Mcfe increase in workovers and other. The net decrease per Mcfe in East Texas/North Louisiana is a result of increased production in our Haynesville shale, which has a relatively low lease operating rate per Mcfe, and declines in our Vernon Field and Cotton Valley area, which historically have a higher lease operating rate per Mcfe. As discussed above, the increase in both Appalachia and Permian and other is a result of the divestitures in 2009 of our Ohio and certain Northwestern Pennsylvania producing assets and certain non-strategic Permian producing assets along with declines associated with suspended drilling operations.

	Nine months ended September 30,
	2010						2009						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	$	36,171	$	7,930	$	44,101	$	54,373	$	7,274	$	61,647	$	(18,202	)	$	656		$	(17,546	)
Appalachia		12,063		216		12,279		21,799		1,014		22,813		(9,736	)		(798	)		(10,534	)
Permian and other		6,758		683		7,441		8,340		1,030		9,370		(1,582	)		(347	)		(1,929	)
Mid-Continent								17,534		728		18,262		(17,534	)		(728	)		(18,262	)
Total	$	54,992	$	8,829	$	63,821	$	102,046	$	10,046	$	112,092	$	(47,054	)	$	(1,217	)	$	(48,271	)
	Nine months ended September 30,
	2010						2009						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	$	0.54	$	0.12	$	0.66	$	0.82	$	0.11	$	0.93	$	(0.28	)	$	0.01		$	(0.27	)
Appalachia		1.58		0.03		1.61		1.46		0.07		1.53		0.12			(0.04	)		0.08
Permian and other		1.27		0.13		1.40		1.17		0.14		1.31		0.10			(0.01	)		0.09
Mid-Continent								1.08		0.04		1.12		(1.08	)		(0.04	)		(1.12	)
Operating costs per Mcfe		0.69		0.11		0.80		0.97		0.10		1.07		(0.28	)		0.01			(0.27	)

Midstream operations

Until our adoption of the equity method of accounting in connection with the formation of TGGT in August 2009, our midstream revenues were principally derived from three of our wholly owned subsidiaries:

• TGG Pipeline, Ltd., which owns gathering systems in East Texas and North Louisiana;

• Talco Midstream Assets, Ltd., which owns gathering systems in East Texas; and

• Vernon Gathering LLC, a gathering system located in Jackson Parish, Louisiana.

Revenues in our midstream segment were primarily derived from sales of natural gas purchased for resale and fees earned from gathering, treating and compression of natural gas. We do not own any natural gas processing facilities.

TGGT now holds our East Texas/North Louisiana midstream assets, exclusive of the Vernon Field midstream assets. TGGT is accounted for using the equity method of accounting. The net operations of Vernon Gathering are now reflected in “Gathering and transportation” on our Condensed Consolidated Statements of Operations.

TGGT completed a 36-inch header gathering system in North Louisiana in the first quarter of 2010 which gathers and treats natural gas from our Haynesville shale and Cotton Valley wells, principally in Desoto Parish, Louisiana. TGGT’s average daily throughput during the third quarter of 2010 was approximately 1.2 Bcf. We expect this throughput to continue to increase as we accelerate development in the Haynesville shale areas.

41

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 $11.6 million and $35.5 million for the three and nine months ended September 30, 2010, respectively, compared to $4.9 million and $12.9 million for the three and nine months ended September 30, 2009, respectively. The overall increase in gathering and transportation expenses is a result of new firm transportation agreements in the Haynesville area, which commenced in February 2010, along with the fees charged by TGGT.

In connection with our change from reporting our midstream operations as a separate business segment, we began reporting the net results of operations from our Vernon Gathering system as a component of gathering and transportation expenses in the third quarter of 2009.

Production and ad valorem taxes

Production and ad valorem taxes for the three months ended September 30, 2010 decreased by $7.6 million, or 71.7%, over the same period in 2009. Production and ad valorem taxes for the nine months ended September 30, 2010 decreased by $13.0 million, or 40.2%, over the same period in 2009. On a percentage of revenue basis, before the impact of derivative financial instruments, production and ad valorem taxes were 2.3% of gross oil and natural gas sales for the three months ended September 30, 2010, compared with 8.5% during the same period in the prior year and 5.1% of gross oil and natural gas sales for the nine months ended September 30, 2010, compared with 7.3% during the same period in the prior year.

The decrease in the percentage of revenue basis for the three and nine months ended September 30, 2010 is primarily the result of the receipt of severance tax holidays on our deep wells in Louisiana. 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. Approval of these holidays is on a well by well basis, and corresponding credits are not recognized until approvals are received. In our other operating areas, production taxes are predominantly price dependent.

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 raised its severance tax rate to $0.33 per Mcf from $0.29 per Mcf effective July 1, 2009, decreased the rate to $0.164 per Mcf effective July 1, 2010. In addition, the Commonwealth of Pennsylvania has recently enacted legislation that budgets for revenue from the extraction of Marcellus shale natural gas with an effective date for implementation no later than January 1, 2011. However, the state legislature has not agreed on the funding mechanism yet.

Overall, our severance and ad valorem tax rates per Mcfe were $0.10 per Mcfe for the three months ended September 30, 2010 compared with $0.33 per Mcfe for the three months ended September 30, 2009 and $0.24 per Mcfe for the nine months ended September 30, 2010 compared with $0.31 per Mcfe for the nine months ended September 30, 2009. 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.

42

	For the three months ended September 30,
	2010											2009
(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	$	106,649		26,045	$	1,513		1.4	%	$	0.06	$	69,252		20,573	$	6,510		9.4	%	$	0.32
Appalachia		7,316		1,608		209		2.9	%		0.13		18,981		4,743		543		2.9	%		0.11
Permian and other		17,025		1,823		1,293		7.6	%		0.71		14,430		1,898		1,548		10.7	%		0.82
Mid-Continent		—		—		—		—			—		22,830		4,722		2,051		9.0	%		0.43
Total	$	130,990		29,476	$	3,015		2.3	%		0.10	$	125,493		31,936	$	10,652		8.5	%		0.33
	For the nine months ended September 30,
	2010											2009
(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	$	290,998		66,895	$	13,677		4.7	%	$	0.20	$	256,128		66,530	$	19,796		7.7	%	$	0.30
Appalachia		38,582		7,618		1,481		3.8	%		0.19		70,940		14,893		1,913		2.7	%		0.13
Permian and other		50,748		5,301		4,243		8.4	%		0.80		43,257		7,153		4,703		10.9	%		0.66
Mid-Continent		—		—		—		—			—		73,628		16,224		6,034		8.2	%		0.37
Total	$	380,328		79,814	$	19,401		5.1	%		0.24	$	443,953		104,800	$	32,446		7.3	%		0.31

Depletion

Our depletion expense for the three and nine months ended September 30, 2010 increased by $5.2 million, or 11.6%, and decreased by $42.7 million, or 25.5%, respectively, from the same periods in 2009. The decrease for the nine months ended September 30, 2010 was due primarily to a lower depletable full cost pool balance resulting from $1.3 billion of ceiling test write-downs during the first quarter of 2009, the 2009 Divestitures and joint venture transactions during the third and fourth quarters of 2009. These factors decreased our per unit depletion rate from $1.60 per Mcfe for the nine months ended September 30, 2009 to $1.57 per Mcfe for the nine months ended September 30, 2010. The quarter to quarter increase from $1.40 per Mcfe for the three months ended September 30, 2009 to $1.69 per Mcfe for the three months ended September 30, 2010 was primarily the result of increased drilling on proved undeveloped locations in the Haynesville area. We expect the depletion rate to continue to increase during 2010 as the East Texas/North Louisiana Carry is utilized.

Depreciation and amortization

Our depreciation and amortization costs for the three and nine months ended September 30, 2010 decreased by $2.2 million and $7.1 million, or 37.2% and 35.7%, respectively, from the same periods in 2009. The primary reason for the decrease was the sale of our gas gathering assets to form our equity investment in TGGT during the third quarter of 2009.

Accretion of discount on asset retirement obligations for the three and nine months ended September 30, 2010 decreased by $0.9 million and $2.9 million, or 53.0% and 50.1%, respectively, from the same periods in 2009. The decrease was due to the divestitures we completed in 2009 and 2010, including the sale of our Mid-Continent division, the East Texas/North Louisiana JV, and the Appalachia JV, offset by significant well additions and related future plugging liabilities in connection with our 2009 Haynesville activity.

Write-down of oil and natural gas properties

There was no ceiling test write-down for the three or nine months ended September 30, 2010.

For the nine months ended September 30, 2009, we recognized a ceiling test write-down of approximately $1.3 billion to our proved oil and natural gas properties.

43

General and administrative

The following table presents our general and administrative expenses for the three and nine months ended September 30, 2010 and 2009:

	Three months ended September 30,						Quarter to quarter change			Nine months ended September 30,						Period to period change
(in thousands, except per unit rate)	2010			2009			2010-2009			2010			2009			2010-2009
General and administrative costs:
Gross general and administrative expense	$	32,186		$	31,479		$	707		$	97,864		$	94,209		$	3,655
Operator overhead reimbursements		(3,906	)		(6,461	)		2,555			(11,778	)		(19,180	)		7,402
Capitalized acquisition and development charges		(4,246	)		(3,371	)		(875	)		(9,767	)		(10,347	)		580
Net general and administrative expense	$	24,034		$	21,647		$	2,387		$	76,319		$	64,682		$	11,637
General and administrative expense per Mcfe	$	0.82		$	0.68		$	0.14		$	0.96		$	0.62		$	0.34

Our general and administrative costs for the three months ended September 30, 2010 were $24.0 million, or $0.82 per Mcfe, compared to $21.6 million, or $0.68 per Mcfe, for the same period in 2009, an increase of $2.4 million, or 11.0%. Our general and administrative costs for the nine months ended September 30, 2010 were $76.3 million, or $0.96 per Mcfe, compared to $64.7 million, or $0.62 per Mcfe, for the same period in 2009, an increase of $11.6 million, or 18.0%.

Significant components of the net increases for the three and nine months ended September 30, 2010 include the following items:

• increased salary and benefit costs of $1.3 million and $6.4 million for the three and nine months ended September 30, 2010, respectively, due primarily to technical employees hired to exploit our shale resource asset base;

• increased legal costs of $2.0 million and $4.6 million for the three and nine months ended September 30, 2010, respectively, due to various claims and settlements;

• increased share-based compensation costs of $2.2 million for the nine months ended September 30, 2010 due primarily to the annual stock option grant in 2009 and the acceleration of option vesting of certain employees impacted by the 2009 Divestitures;

• increased building rent and associated fees of $1.6 million and $2.9 million for the three and nine months ended September 30, 2010, respectively, due to expansion of our Dallas office;

• increased travel costs of $0.4 million and $1.4 million for the three and nine months ended September 30, 2010, respectively, primarily related to joint venture activities; and

• reduced operator overhead recoveries of $2.6 million and $7.4 million for the three and nine months ended September 30, 2010, respectively. These reduced operator overhead recoveries reflect the impact of the 2009 Divestitures.

The above increases are partially offset by reimbursements of technical and administrative service costs of $4.7 million and $14.8 million for the three and nine months ended September 30, 2010, respectively, from various service agreements with BG Group and an increase in capitalized charges of $0.9 million for the three months ended September 30, 2010 compared to the same period in 2009 due to increased personnel during the year and 2010 salary increases.

44

Interest expense

Our interest expense decreased approximately $38.3 million and $96.2 million for the three and nine months ended September 30, 2010 from the same periods in 2009. The quarter and year-to-date decreases were primarily due to the interest and deferred financing costs related to the $300.0 million senior unsecured term credit agreement, or the Term Credit Agreement, which was paid off on August 14, 2009, along with lower average balances on our credit agreement, the expiration of our interest rate swaps and higher capitalized interest. These decreases were partially offset by the interest expense on 2018 Notes and the related amortization of deferred financing costs. The following table presents the components of our interest expense:

	Three months ended September 30,						Quarter to quarter change			Nine months ended September 30,						Period to period change
(in thousands)	2010			2009			2010-2009			2010			2009			2010-2009
Interest expense:
2011 Notes (1)	$	7,293		$	7,156		$	137		$	21,532		$	21,510		$	22
2018 Notes (1)		2,385			—			2,385			2,385			—			2,385
EXCO Resources Credit Agreement		3,989			6,093			(2,104	)		8,613			19,786			(11,173	)
EXCO Operating credit agreement (2)		—			5,110			(5,110	)		6,008			21,736			(15,728	)
Term credit agreement		—			4,669			(4,669	)		—			19,752			(19,752	)
Amortization of deferred financing costs on EXCO Resources Credit Agreement		1,223			2,675			(1,452	)		2,516			4,370			(1,854	)
Amortization of deferred financing costs on EXCO Operating credit agreement (2)		—			3,362			(3,362	)		4,436			4,870			(434	)
Amortization of deferred financing costs on Term Credit Agreement		—			15,426			(15,426	)		—			37,755			(37,755	)
Amortization of deferred financing costs on 2018 Notes		76			—			76			76			—			76
Interest rate swaps settlements		—			3,550			(3,550	)		2,063			8,036			(5,973	)
Fair market value adjustment on interest rate swaps		—			(245	)		245			(2,018	)		(4,250	)		2,232
Capitalized interest		(6,595	)		(1,140	)		(5,455	)		(12,709	)		(3,937	)		(8,772	)
Other interest expense		69			81			(12	)		648			132			516
Total interest expense	$	8,440		$	46,737		$	(38,297	)	$	33,550		$	129,760		$	(96,210	)

(1) We issued the 2018 Notes on September 15, 2010 and used a portion of the proceeds to redeem the 2011 Notes on October 15, 2010.

(2) On April 30, 2010, the EXCO Operating credit agreement was consolidated into the EXCO Resources Credit Agreement.

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 prices, but also limit the benefits we would realize if prices increase. When prices for oil and natural gas are volatile, a significant portion of the effect of our derivative financial instrument management activities consists of non-cash income or expenses due to changes in the fair value of our derivative financial instrument contracts. Cash charges or gains only arise from payments made or received on monthly settlements of contracts or if we terminate a contract prior to its expiration. We expect that our revenues will continue to be significantly impacted in future periods by changes in the value of our derivative financial instruments as a result of volatility in oil and natural gas prices and the amount of future production volumes subject to derivative financial instruments.

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

	Three months ended September 30,					Quarter to quarter change			Nine months ended September 30,						Period to period change
(in thousands)	2010		2009			2010 - 2009			2010			2009			2010 - 2009
Derivative financial instrument activities:
Cash settlements on derivative financial instruments, excluding early terminations	$	43,075	$	113,563		$	(70,488	)	$	128,724		$	354,131		$	(225,407	)
Cash settlements on early terminations of derivative financial instruments		—		—			—			37,936			—			37,936
Non-cash change in fair value of derivative financial instruments		13,134		(99,045	)		112,179			(10,595	)		(149,246	)		138,651
Total derivative financial instrument activities	$	56,209	$	14,518		$	41,691		$	156,065		$	204,885		$	(48,820	)

45

The use of derivative financial instruments allows us to limit the impacts 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 increased from $4.24 during the nine months ended September 30, 2009 to $4.77 during the nine months ended September 30, 2010. Excluding the impact of the cash settlement on early terminations of certain derivatives, average realized prices per Mcfe after the impact of our derivative financial instruments increased our price from $4.77 to $6.38 per Mcfe during the nine months ended September 30, 2010 and increased our price from $4.24 to $7.62 per Mcfe for the nine months ended September 30, 2009.

	Three months ended September 30,				Quarter to quarter change			Nine months ended September 30,				Period to period change
Realized pricing:	2010		2009		2010 - 2009			2010		2009		2010 - 2009
Oil per Bbl	$	72.85	$	63.88	$	8.97		$	74.13	$	50.89	$	23.24
Natural gas per Mcf		4.15		3.45		0.70			4.47		3.88		0.59
Natural gas equivalent per Mcfe	$	4.44	$	3.93	$	0.51		$	4.77	$	4.24	$	0.53
Cash settlements on derivative financial instruments, excluding early terminations		1.46		3.56		(2.10	)		1.61		3.38		(1.77	)
Net price per Mcfe, including derivative financial instruments before early terminations		5.90		7.49		(1.59	)		6.38		7.62		(1.24	)
Cash settlements on early terminations of derivative financial instruments		—		—		—			0.48		—		0.48
Net price per Mcfe, derivative financial instruments	$	5.90	$	7.49	$	(1.59	)	$	6.86	$	7.62	$	(0.76	)

Our total cash settlements for the three months ended September 30, 2010 increased revenue by $43.1 million, or $1.46 per Mcfe, compared to $113.6 million, or $3.56 per Mcfe, for the same period in 2009. Our total cash settlements for the nine months ended September 30, 2010, including the derivatives settled early, increased revenue by $166.7 million, or $2.09 per Mcfe, compared $354.1million, or $3.38 per Mcfe, for the same period in 2009. As noted above, the significant fluctuations between settlements of receipts on our derivative financial instruments demonstrate the aforementioned volatility in prices.

Our non-cash mark- to- market changes in the value of our oil and natural gas derivative financial instruments for the three and nine months ended September 30, 2010 resulted in gains of $13.1 million and losses of $10.6 million, respectively, compared to losses of $99.0 million and $149.2 million, respectively, for the same period in the prior year. The significant fluctuation was, again, attributable to high volatility in the prices for oil and natural gas between each of the years. The ultimate settlement amount of the unrealized portion of the derivative financial instruments is dependent on future commodity prices.

We expect to continue our comprehensive derivative financial instrument program to enhance our ability to execute our business plan over the entire commodity price cycle, protect our returns on investment, and manage our capital structure. The percentage of expected production covered by derivative financial instruments as we enter 2011 is less than we have historically covered. In addition, our existing derivative financial instruments are at significantly higher prices than prices which are available in the current market for future production.

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal through February 14, 2010 at LIBOR ranging from 2.45% to 2.8%. For the nine months ended September 30, 2010, we had realized losses from payments of $2.1 million and non-cash unrealized gains of $2.0 million. For the three months ended September 30, 2009, we had realized losses from payments of $3.6 million and non-cash unrealized gains of $0.2 million attributable to our interest rate swaps. For the nine months ended September 30, 2009, we had realized losses from payments of $8.0 million and non-cash unrealized gains of $4.3 million. These swaps expired on February 14, 2010 and as of September 30, 2010 we have not entered into any new interest rate swaps.

Income taxes

Our effective income tax rate for the three and nine months ended September 30, 2010 was a benefit of 1.4% and an expense of 0.5%, respectively. The prior year’s effective rates were (0.5)% and 0% for the three and nine months ended September 30, 2009, respectively. During the three and nine months ended September 30, 2010, we utilized $27.4 million and $305.1 million of our accumulated valuation allowance, respectively. Our accumulated valuation allowance as of September 30, 2010 is approximately $372.6 million and can be used against future deferred tax benefits. For the three and nine months ended September 30, 2009, we recognized a valuation allowance of $168.7 million and $289.9 million,

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respectively, against future deferred tax benefits. The 2009 valuation allowance increases were due primarily to non-cash ceiling test write-downs. The valuation allowance is primarily attributable to the ceiling test write-downs, which occurred in the first quarter of 2009 and 2008, that have resulted in recognition of operating losses that caused the book basis of our proved oil and natural gas properties to be less than the tax basis of those properties. 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 allowance for the three and nine months ended September 30, 2010 would have been 42.9% and 40.7%, respectively, and for the three and nine months ended September 30, 2009 would have been 38.7% and 39.3%, respectively. A substantial portion of our stock-based compensation included in our results of operations for the three and nine months ended September 30, 2010 and 2009 are in the form of incentive stock options, which are not deductible for tax purposes until a disqualifying event occurs. The change in the tax rate from the prior year, without giving consideration to the impact of the deferred income tax valuation allowance, is mainly a result of a rate change last year in our state income taxes.

Our liquidity, capital resources and capital commitments

Overview

Our primary sources of capital resources and liquidity are internally generated cash flows from operations, borrowing capacity under the EXCO Resources Credit Agreement, dispositions of non-strategic assets, joint ventures and capital markets, when 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. The capital expenditure requirements to develop our Haynesville/Bossier shale, Marcellus shale and related midstream infrastructures are significant. While we expect our shale development programs to contribute significant reserve additions and production volumes, the required development capital to achieve these results may exceed internally generated cash flow in 2010 and 2011. Continued volatility of commodity prices or an extended downward trend in natural gas prices may alter our development in 2011 and 2012. We are presently constructing our 2011 capital budgets.

Other factors which are expected to impact our liquidity, capital resources and capital commitments as we enter 2011 include (i) the expiration of the East Texas/North Louisiana Carry in the first quarter of 2011, (ii) continued depressed commodity prices, particularly natural gas, (iii) continued expansion of our technical personnel required to support our drilling programs, particularly in Appalachia, (iv) decreases in the percentage of production covered by derivative financial instruments, coupled with expiration of higher-priced derivative financial instruments and (v) continued upward trends in service costs related to horizontal drilling and completions. Each of the aforementioned factors may require us to use borrowing capacity under our EXCO Resources Credit Agreement to fund our operations.

We recently completed the offering of the 2018 Senior Notes, redeemed the 2011 Notes and reduced borrowings under the EXCO Resources Credit Agreement. The offering extended our maturities and provided us with substantial liquidity to execute these development programs. Other capital expenditures, including midstream investments and acquisitions, may require additional funding from other sources. TGGT is currently evaluating the establishment of a credit facility to fund future capital expenditures.

Acquisitions are generally not budgeted as they tend to be opportunity driven and our current strategy is to limit acquisition activity to our target areas (East Texas/North Louisiana and Appalachia) for contiguous acreage blocks or “bolt-on” acreage, as economic conditions permit.

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The following table presents our liquidity and financial position as of September 30, 2010 and October 29, 2010:

(in thousands)	September 30, 2010		October 29, 2010
Cash (1)	$	151,373	$	149,614
Drawings under the EXCO Resources Credit Agreement	$	254,400	$	294,400
2018 Notes (2)		750,000		750,000
Total debt		1,004,400		1,044,400
Net debt	$	853,027	$	894,786
Borrowing base	$	1,200,000	$	1,000,000
Total of unused borrowing base (3)	$	930,398	$	690,252
Unused borrowing base plus cash (1) (3)	$	1,081,771	$	839,866

(1) Includes restricted cash of $100.2 million at September 30, 2010 and $126.3 million at October 29, 2010.

(2) Excludes unamortized bond discount of $11.0 million at September 30, 2010 and October 29, 2010.

(3) Net of letters of credit of $15.2 million at September 30, 2010 and $15.3 million at October 29, 2010.

Recent events affecting liquidity

On September 15, 2010, we issued the 2018 Notes. Net proceeds, after an original issue discount, commissions and fees and expenses were $724.4 million, a portion of which were used to redeem all $444.7 million principal amount and accrued interest of the 2011 Notes and pay down $271.6 million of the balance outstanding under the EXCO Resources Credit Agreement. As of result of the offering, current maturities of debt were extended to 2018 and availability under our credit agreement at September 30, 2010 was increased.

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, privately negotiated transactions or through a structured share repurchase program. Funds for the share repurchases will be from available cash or from availability under the EXCO Resources Credit Agreement. As of October 29, 2010, we have purchased 539,221 shares of our common stock at an aggregate cost of $7.5 million.

We closed the Appalachia JV on June 1, 2010 with BG Group, which resulted in net proceeds of approximately $835.2 million, subject to final closing adjustments and used $780.0 million of those proceeds to reduce the outstanding balance on the EXCO Resources Credit Agreement. We expect that impacts from the Appalachia JV to our capital resources and liquidity will include the following:

• a reduction in net operating cash flow reflecting the sale of 50% of our interest to BG Group in the existing shallow production of approximately 17.5 Mmcfe per day;

• increased drilling and development activities, which presently include an expected increase from two horizontal drilling rigs to three by the end of 2010;

• decreases in our net share of Appalachian drilling costs arising from the Appalachia Carry; and

• increases in midstream capital expenditures to construct gathering systems, pipelines and other midstream infrastructure to support future production from the Marcellus shale.

On May 14, 2010, EXCO and BG Group closed the joint purchase of Common Resources, L.L.C., or the Common Transaction, which owns properties in Shelby, San Augustine and Nacogdoches Counties, Texas in the Haynesville and Bossier shales. The total purchase price paid at closing was approximately $442.1 million ($221.0 million net to EXCO), subject to post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under the EXCO Resources Credit Agreement. The development of these assets is governed by the East Texas/North Louisiana JV.

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On June 30, 2010, EXCO and BG Group jointly closed the purchase of properties in Shelby, San Augustine and Nacogdoches Counties, Texas from Southwestern Energy Company, or the Southwestern Transaction. The purchase price paid at the closing was $355.8 million ($177.9 million net to EXCO), subject to post-closing purchase price adjustments. Our net acquisition price was financed with borrowings under the EXCO Resources Credit Agreement. The development of these assets is governed by the East Texas/North Louisiana JV. The majority of the assets acquired in the Southwestern Transaction represent incremental working interests in properties that EXCO and BG Group acquired in the Common Transaction.

On October 6, 2010, the lenders under the EXCO Resources Credit Agreement completed their regular semi-annual redetermination of our borrowing base, resulting in a borrowing base of $1.0 billion as requested by EXCO following the offering of the 2018 Notes. The next redetermination of the borrowing base is scheduled to occur on April 1, 2011.

Our capital budget presently focuses on development of our Haynesville and Bossier shale plays in East Texas/North Louisiana and the Marcellus shale in Appalachia. The East Texas/North Louisiana JV and the Appalachia JV reduced our ownership interest in our properties by 50%. The joint ventures contain provisions for BG Group to fund 75% of our share of drilling and development costs on horizontal wells which will provide us with substantial economic benefit toward development of these shale resources. As of September 30, 2010, approximately $134.2 million of the East Texas/North Louisiana Carry remains unused and $147.1 million of the Appalachia Carry remains unused. We expect that the East Texas/North Louisiana Carry will be fully utilized during the first quarter of 2011.

We are in the process of preparing our operating and capital budgets for 2011 for EXCO and for our upstream and midstream joint ventures with BG. Although our strategy is to allocate our capital to those projects capable of yielding acceptable returns at current natural gas prices, ongoing weakness in natural gas prices continues to be of significant concern, which requires we maintain flexibility in our budgets. Our present plans are to continue drilling horizontal wells in DeSoto Parish, Louisiana, the Shelby Trough in East Texas/North Louisiana and Appalachia in 2011. Subject to approval of the 2011 budget by our Board of Directors, we are presently evaluating an increase in the number of operated drilling rigs from 25 at September 30, 2010 to an average of 29 in 2011. Although we will benefit from the Appalachia Carry, we anticipate that our 2011 capital expenditures for drilling and completion, commitment to fund ventures with BG Group and our Permian and maintenance capital will increase significantly over our 2010 capital expenditures.

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

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Sources and uses of funds

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

	Nine months ended September 30,
(amounts in thousands)	2010			2009
Cash flows provided by operating activities	$	275,996		$	349,857
Cash flows provided by (used in) investing activities		(44,163	)		849,762
Cash flows used in financing activities		(249,116	)		(1,201,077	)
Net decrease in cash	$	(17,283	)	$	(1,458	)

Our primary sources of cash for the nine months ended September 30, 2010 were proceeds from our Appalachia JV and other assets sales, proceeds from the issuance of the 2018 Notes in September and cash flows from operating activities, which together provided approximately $2.0 billion in cash. We utilized these cash inflows to redeem our 2011 Notes, fund our drilling and development activities and close acquisitions.

For the nine months ended September 30, 2009, our primary sources of cash were from the East Texas/North Louisiana JV and TGGT transactions in August 2009, successful completion of our 2009 asset divestiture program, and cash flows from operating activities, which together provided approximately $1.8 billion in cash. These cash sources were offset by cash uses of approximately $436.4 million in investments in drilling and development and midstream equity investments and net reduction in debt of over $1.3 billion.

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, (iv) costs of our general and administrative activities and (v) interest expense and other financing related costs in 2010. Our cash flows from operations have been significantly impacted by fluctuations in oil and natural gas prices and our production volumes. Our production volumes in 2010 have been negatively impacted by our 2009 asset divestiture program and by the East Texas/North Louisiana JV in August 2009 and the Appalachia JV in June 2010. However, based upon continued success of our Haynesville shale drilling program, we expect to replenish the volumes toward the end of 2010 or early 2011. Prices of oil and natural gas have historically been, and continue to be, very volatile. We use derivative financial instruments to help mitigate this price volatility. Commodity prices, particularly natural gas, experienced 52-week lows in October 2010.

Net cash provided by operating activities was $276.0 million for the nine months ended September 30, 2010 compared with $349.9 million for the nine months ended September 30, 2009. The 21.1% decrease is attributable primarily to lower production volumes resulting from divestitures and lower cash settlements of our oil and natural gas derivatives offset by higher average oil and natural gas prices during the first nine months of 2010 compared with average prices during the same period in 2009. At October 29, 2010, our cash and cash equivalents balance was $23.3 million and our restricted cash account, which is principally used for Haynesville development operations, was $126.3 million.

We have made cash dividend payments to our common shareholders of $21.2 million during 2010 and repurchased $7.5 million of our common stock.

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Investing activities and transactions

Our investing activities consist primarily of drilling and development expenditures, capital contributions to our jointly-owned midstream ventures, and acquisitions, including prospective acreage acquisitions in our target areas. Our recent acquisitions have been focused primarily on undeveloped shale acreage in our core areas and have been funded primarily with borrowings under our 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 our credit agreement.

Acquisitions and capital expenditures

The following table presents our capital expenditures for the three and nine months ended September 30, 2010 and 2009 and does not include expected reimbursements from BG Group of approximately $198.0 million:

	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2010		2009		2010		2009
Capital expenditures:
Acquisitions	$	57,013	$	3,396	$	509,282	$	3,789
Lease purchases		12,874		35,197		80,259		53,443
Development capital expenditures		88,567		61,274		256,162		258,991
Midstream capital additions		—		20,484		—		53,627
Seismic		4,855		1,316		14,576		9,669
Gas gathering and water pipelines		12,745		751		18,768		1,924
Corporate and other		31,997		6,523		52,890		23,632
Total capital expenditures	$	208,051	$	128,941	$	931,937	$	405,075

Future capital expenditures are subject to a number of variables including production volumes, fluctuations in oil and natural gas prices, availability of borrowings under our credit agreement and ability to service our debt. If our cash flows decline, we may be required to further reduce our capital expenditure budget, which in turn may affect our production in future periods. Continued weakness in natural gas prices, expiration of our higher priced derivative financial instruments and projected increased capital expenditures in 2011 will likely require increased borrowing under the EXCO Resources Credit Agreement to meet our present production targets.

2010 Capital budget

Presently, our net capital budget, including acreage reimbursements from BG Group is approximately $496.8 million for 2010. We also expect to contribute a total of $143.5 million to our midstream investments for 2010. We are presently contractually obligated to spend $122.3 million. The amended capital budget reflects a 2.9% increase from 2009 actual capital expenditures, excluding acquisitions. The remaining 2010 capital budget of $168.7 million is net of expected East Texas/North Louisiana Carry and acreage reimbursements from BG Group. As of September 30, 2010, we have a $147.1 million drilling carry remaining from the Appalachia JV. Utilization of that carry commenced during the third quarter of 2010.

Financing activities

Credit agreements and long-term debt

As of October 29, 2010, we had total debt outstanding of approximately $1.0 billion consisting of borrowings under the EXCO Resources Credit Agreement of $294.4 million and $750.0 million of Senior Notes due on September 15, 2018. Terms and conditions of each of the debt obligations are discussed below. On September 15, 2010, we provided notice to the Trustee for our 2011 Notes of our intent to fully redeem all of the $444.7 million 2011 Notes. Redemption occurred on October 15, 2010. Funds to redeem

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the 2011 Notes were provided from net proceeds from issuance of the 2018 Notes. Our ability to borrow from sources other than the EXCO Resources Credit Agreement is subject to certain restrictions imposed by our lenders and the indenture governing our 2018 Notes. These agreements contain limitations and restrictions on incurring additional indebtedness and pledging our assets.

EXCO Resources Credit Agreement

The EXCO Resources Credit Agreement, as amended, has a current borrowing base of $1.0 billion. On October 29, 2010, we had $294.4 million of outstanding indebtedness and $690.3 million of available borrowing capacity under the EXCO Resources Credit Agreement. The majority of EXCO’s subsidiaries are guarantors under the EXCO Resources Credit Agreement, except those subsidiaries which are jointly held with BG Group and two other subsidiaries that are wholly owned by EXCO Operating Company. The EXCO Resources Credit Agreement permits certain investments, loans and advances to the unrestricted subsidiaries that are jointly held with BG Group. On July 19, 2010, the EXCO Resources Credit Agreement was amended to allow for stock repurchases of up to $200.0 million. On September 15, 2010, the agreement was further amended to permit the redemption of the 2011 Notes by issuance of our 2018 Notes.

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 all Proved Reserves (as defined in the agreement) during the first two years of the forthcoming five year period, 90% of the forecasted production for any month during the third year of the forthcoming five year period and 85% of the forecasted production 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.

The interest rate ranges from LIBOR plus 200 basis points, or bps, to LIBOR plus 300 bps depending upon borrowing base usage. The facility also includes an Alternate Base Rate, or ABR, pricing alternative ranging from ABR plus 100 bps to ABR plus 200 bps depending upon borrowing base usage. Based on a one month LIBOR of 0.25% on October 29, 2010, we would incur an interest rate of approximately 2.5% on any new indebtedness we may incur under the EXCO Resources Credit Agreement.

As of September 30, 2010, we were in compliance with the financial covenants contained in the EXCO Resources Credit Agreement, which require that we:

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

• not permit our ratio of consolidated funded indebtedness (as defined in the agreement) to consolidated EBITDAX (as defined in the agreement) to be greater than 3.50 to 1.0 at the end of any fiscal quarter ending on or after March 31, 2010.

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

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2018 Notes

On September 15, 2010 we closed an underwritten offering of $750.0 million aggregate principal amount of 7.5% senior unsecured notes maturing on September 15, 2018. We received proceeds of approximately $724.4 million from the offering after deducting an original issue discount of $11.0 million and commissions, estimated offering fees and expenses of $14.6 million. The remaining net proceeds from the offering were used to redeem the 2011 Notes with the balance of approximately $271.6 million being used to pay a portion of the outstanding balance under the EXCO Resources Credit Agreement. The bonds are guaranteed on a senior unsecured basis by EXCO’s consolidated subsidiaries, other than EXCO Caddo Acquisition, LLC, EXCO Water Resources, LLC and all of our jointly-held equity investments with BG Group. Our midstream equity investments with BG Group are designated as unrestricted subsidiaries under the indenture governing the 2018 Notes.

As of September 30, 2010, $750.0 million in principal was outstanding on our 2018 Notes. The unamortized discount on the 2018 Notes at September 30, 2010 was $11.0 million. The estimated fair value of the 2018 Notes, based on quoted market prices, was $740.6 million on September 30, 2010.

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 guarantor subsidiaries to:

• incur or guarantee additional debt and issue certain types of preferred stock;

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

• make certain investments;

• create liens on our assets;

• enter into sale/leaseback transactions;

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

• engage in transactions with our affiliates;

• transfer or issue shares of stock of subsidiaries;

• transfer or sell assets; and

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

Other financing activities

On July 10, 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 under our existing debt facilities. As of October 29, 2010, we have purchased 539,221 shares of our common stock at an aggregate cost of $7.5 million.

We paid cash dividends on our common stock of $21.2 million during the nine months ended September 30, 2010.

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.

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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 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 and related borrowings under the EXCO Resources Credit Agreement. 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, 2010, 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 2010		13,940	$	7.21		113	$	114.96
2011		31,025		6.55		548		111.32
2012		16,470		6.05		92		109.30
2013		5,475		5.99		—		—

Interest rate swaps

In January 2008, we entered into interest rate swaps to mitigate our exposure to fluctuations in interest rates on $700.0 million in principal of our credit agreements through February 14, 2010 at LIBOR ranging from 2.45% to 2.8%. Our interest rate swaps expired in February 2010 and we have not entered into any new agreements.

Off-balance sheet arrangements

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

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Contractual obligations and commercial commitments

The following table presents a summary of our contractual obligations at September 30, 2010:

	Payments due by period
(in thousands)	Less than one year		One to three years		Three to five years		More than five years		Total
2018 Notes	$	—	$	—	$	—	$	750,000	$	750,000
Long-term debt - EXCO Resources Credit Agreement (1)		—		254,400		—		—		254,400
Firm transportation services and other fixed commitments (2)		33,525		63,026		62,440		145,654		304,645
Operating leases		65,933		111,653		17,051		750		195,387
Drilling contracts		74,287		49,684		2,950		—		126,921
Total contractual obligations	$	173,745	$	478,763	$	82,441	$	896,404	$	1,631,353

(1) The EXCO Resources Credit Agreement, as amended, matures on April 30, 2014.

(2) Firm transportation services reflect contracts whereby EXCO commits to transport a minimum quantity of natural gas on a shippers’ pipeline. Other fixed commitments include salt water disposal arrangements. Whether or not EXCO delivers the minimum quantity, we pay the fees as if the quantities were delivered.

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 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 instrument’s fair value currently in earnings.

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices for natural gas. Pricing for oil and natural gas production is volatile.

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The following table sets forth our oil and natural gas derivative financial instruments measured at fair value as of September 30, 2010.

(in thousands, except prices)	Volume Mmbtus/Bbls		Weighted average strike price per Mmbtu/Bbl		Fair value at September 30, 2010
Natural gas:
Swaps:
Remainder of 2010		13,940	$	7.21	$	45,081
2011		31,025		6.55		64,547
2012		16,470		6.05		15,793
2013		5,475		5.99		3,737
Total natural gas		66,910				129,158
Oil:
Swaps:
Remainder of 2010		113		114.96		3,763
2011		548		111.32		14,373
2012		92		109.30		1,974
Total oil		753				20,110
Total oil and natural gas and derivatives					$	149,268

At September 30, 2010, the average forward NYMEX oil prices per Bbl for the remainder of 2010 and for 2011 were $81.20 and $84.83, respectively, and the average forward NYMEX natural gas prices per Mmbtu for the remainder of 2010 and for 2011 were $3.94 and $4.44, 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, 2010, for the remainder of 2010, if the settlement price exceeds the actual weighted average strike price of $114.96 per Bbl, then a reduction in other income would be recorded for the difference between the settlement price and $114.96 per Bbl, multiplied by the hedged volume of 113 Mbbls. Conversely, if the settlement price is less than $114.96 per Bbl, then an increase in other income would be recorded for the difference between the settlement price and $114.96 per Bbl, multiplied by the hedged volume of 113 Mbbls. For example, for a hedged volume of 113 Mbbls, if the settlement price is $115.96 per Bbl then other income would decrease by $0.1 million. Conversely, if the settlement price is $113.96 per Bbl, other income would increase by $0.1 million.

Interest rate risk

At September 30, 2010, 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 our 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, 2010, we had approximately $254.4 million in outstanding borrowings

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under the EXCO Resources Credit Agreement. A 1% change in interest rates based on the variable borrowings as of September 30, 2010 would result in an increase or decrease in our interest costs of $2.5 million per year. The interest we pay on these borrowings is set periodically based upon market rates.

In January 2008, we entered into interest rate swaps on $700.0 million in principal of our credit agreement through February 14, 2010 at LIBOR ranging from 2.45% to 2.8%. These interest rate swaps expired in February 2010 and we have not entered into any new agreements.

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, 2010 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, 2010 that have materially affected, or are reasonably likely to materially affect, EXCO’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1A. Risk Factors

We conduct a substantial portion of our operations through joint ventures, and our failure to continue such joint ventures or resolve any material disagreements with our partners could have a material adverse effect on the success of these operations, our financial condition and our results of operations.

We conduct a substantial portion of our operations through joint ventures with third parties, principally BG Group, and as a result, the continuation of such joint ventures is vital to our continued success. We may also enter into other joint venture arrangements in the future. In many instances we depend on these third parties for elements of these arrangements that are important to the success of the joint venture, such as agreed payments of substantial carried costs pertaining to the joint venture and their share of capital and other costs of the joint venture. The performance of these third party obligations or the ability of third parties to meet their obligations under these arrangements are outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of these arrangements, and their value to us, may be adversely affected. If our current or future joint venture partners are unable to meet their obligations, we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights, which may cause disputes among our joint venture parties and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations, these joint ventures and/or our ability to enter into future joint ventures.

Such joint venture arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

• our joint venture partners may share certain approval rights over major decisions;

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• the possibility that our joint venture partners might become insolvent or bankrupt, leaving us liable for their shares of joint venture liabilities;

• the possibility that we may incur liabilities as a result of an action taken by our joint venture partners;

• joint venture partners may be in a position to take action contrary to our instructions or requests or contrary to our policies or objectives;

• disputes between us and our joint venture partners may result in litigation or arbitration that would increase our expenses, delay or terminate projects and prevent our officers and directors from focusing their time and effort on our business;

• that under certain joint venture arrangements, neither joint venture partner may have the power to control the venture, and an impasse could be reached which might have a negative influence on the joint venture; and

• our partners may decide to terminate their relationship with us in any joint venture company or sell its interest in any of these companies and we may be unable to replace such partner or raise the necessary financing to purchase such partner’s interest.

The failure to continue some of our joint ventures or to resolve disagreements with our partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations.

Our joint ventures with BG Group contemplate that we will make significant capital expenditures and subject us to certain legal and financial terms that could adversely affect us.

On August 14, 2009 we closed two joint venture transactions with BG Group, which involved the sale of an undivided 50% interest in an area of mutual interest in certain oil and natural gas properties in East Texas and North Louisiana and a 50% interest in certain midstream operations. The upstream transaction operates as a joint venture pursuant to a joint development agreement under which EXCO acts as the operator. The midstream transaction functions as a 50-50 joint venture between EXCO and BG Group, with neither party having control over the management of, or a controlling beneficial economic interest in, the operations.

On June 1, 2010, we closed our Appalachian joint venture with BG Group. Pursuant to the agreements governing the joint venture, EXCO and BG Group agreed to jointly explore and develop their Appalachian properties, particularly the Marcellus shale. EXCO and BG Group each own a 50% interest in an operating company which will operate the properties, subject to oversight from a management board having equal representation from EXCO and BG Group. In addition, certain midstream assets owned by EXCO were transferred to a newly formed, jointly owned entity, Appalachia Midstream, LLC, through which EXCO and BG Group will pursue the construction and expansion of gathering systems, pipeline systems and treating facilities for anticipated future production from the Marcellus shale.

Each of these joint ventures may require us to make significant capital expenditures. If we do not timely meet our financial commitments under the respective joint venture agreements, our rights to participate in such joint ventures will be adversely affected and other parties to the joint ventures may have a right to acquire a share of our interest in such joint ventures proportionate to, and in satisfaction of, our unmet financial obligations.

EXCO has unconditionally guaranteed its subsidiaries’ performance of the joint venture agreements under the Appalachia joint ventures.

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Certain of our undeveloped leasehold acreage, including acreage recently acquired, is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We have leasehold interests across all of our shale plays that are not currently held by production and are subject to leases with primary or renewed terms expiring over the next several years, including acreage in the Haynesville and Bossier shales that we recently acquired in the Common Transaction and the Southwestern Transaction. Unless we establish production in paying quantities on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties.

While we intend to drill sufficient wells to hold the vast majority of our leasehold interests in all of our major plays, our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On June 26, 2009, the U.S. House of Representatives approved adoption of the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey cap-and-trade legislation, or ACES. The purpose of ACES is to control and reduce emissions of greenhouse gases, or GHGs, in the United States. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to warming of the Earth’s atmosphere resulting in climatic changes. ACES would establish a cap on total emissions of GHGs from certain categories of emission sources in the United States and require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACES, those categories of sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACES’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. If enacted, the net effect of ACES would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACES, the Senate legislation would need to be reconciled with ACES, and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance system that results in fewer allowances being issued over time, but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate will act on climate change legislation or how any bill approved by the Senate would be reconciled with ACES, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for the oil and natural gas we produce.

The U.S. Environmental Protection Agency, or EPA, has also taken recent action related to greenhouse gases under existing authority of the federal Clean Air Act. On December 7, 2009, the EPA issued a notice of its finding and determination that emissions of carbon dioxide, methane, and other GHGs may reasonably be anticipated to endanger the public health and public welfare by, among other things, increasing ground-level ozone, altering the climate, contributing to a rise in sea levels, and harming water resources, agriculture, wildlife, and ecosystems. On March 31, 2010, EPA promulgated regulations controlling GHG emissions from motor vehicles. As a result, EPA was required to begin regulating emissions of GHGs under existing permitting provisions of the federal Clean Air Act. Those permitting provisions could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those permitting requirements. On May 13, 2010, EPA published its “Tailoring Rule” to regulate the permitting of GHG sources under the Clean Air Act’s PSD and Title V programs. Under this rule, permitting requirements, including emission limitations, will be phased in over the next several years depending on the types of facilities and on their GHG emissions. Any

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limitation on emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. On September 22, 2009, EPA finalized a GHG reporting rule, which will require large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions, and, on April 10, 2010, published a proposal to expand that rule to cover oil and gas operations. Although this rule and the proposed amendment to it do not limit the amount of GHGs that can be emitted, they could require us to incur costs to monitor, recordkeep and report emissions of GHGs associated with our operations.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, or the Dodd-Frank Act, which is aimed to modernize and protect the integrity of the U.S. financial system. The Dodd-Frank Act, among other things, sets forth the new framework for regulating certain derivative products, but many aspects of these laws are subject to further rulemaking and will take effect over several years. As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to continue entering into and maintaining derivative financial instrument arrangements. Based upon the limited assessments we are able to make with respect to the Dodd-Frank Act, there is the possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain derivative arrangements. In particular, the Dodd-Frank Act could result in the implementation of (a) position limits and (b) additional regulatory requirements on our derivative arrangements, which could include new margin, reporting, and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. The imposition of these types of requirements or limitations could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. It should be further noted that the use of derivative arrangements can play an important role in our acquisition strategies; therefore, any limitations or changes in our use of derivative arrangements could also affect our future ability to conduct acquisitions.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process, including, for example, the Fracturing Responsibility and Awareness of Chemicals Act, sponsored by Senators Bob Casey (D-PA) and Charles Schumer (D-NY). Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. These bills, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance. In addition, a number of states, such as New York and Pennsylvania, are considering or have implemented more stringent regulatory requirements applicable to fracing, which, such as in the case of New York, could include a moratorium on drilling.

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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, 2010:

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, 2010		0	$	0.00		0	$	200.0 million
August 1 - August 31, 2010		233,283	$	14.01		233,283	$	196.7 million
September 1 - September 30, 2010		305,938	$	13.76		305,938	$	192.5 million
Total		539,221	$	13.87		539,221

(1) On July 19, 2010, we announced a $200.0 million share repurchase program. All of the shares repurchased during the third quarter of 2010 were repurchased pursuant to this plan.

Item 6. Exhibits

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

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SIGNATURES

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

EXCO RESOURCES, INC.

(Registrant)

Date: November 3, 2010	By:	/s/ Douglas H. Miller
		Douglas H. Miller
		Chairman and Chief Executive Officer
	By:	/s/ Stephen F. Smith
		Stephen F. Smith
		President and Chief Financial Officer

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Index to Exhibits

Exhibit Number	Description of Exhibits
2.1	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Operating Company, LP, as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.2	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Resources, Inc., as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.3	Purchase and Sale Agreement, dated June 29, 2009, by and among EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.4	Contribution Agreement, dated August 5, 2009, by and among Vaughan Holding Company, LLC, EXCO Operating Company, LP and BG US Gathering Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
2.5	First Amendment, dated July 13, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
2.6	Second Amendment, dated August 5, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
2.7	Purchase and Sale Agreement, dated September 29, 2009, by and between EXCO—North Coast Energy, Inc., Inc., as seller, and EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., and EV Properties, L.P., as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
2.8	Purchase and Sale Agreement, dated September 30, 2009, by and between EXCO Resources, Inc., as seller, and Sheridan Holding Company I, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
2.9	Membership Interest Transfer Agreement, dated as of May 9, 2010, between EXCO Holding (PA), Inc. and BG US Production Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated June 1, 2010 and filed on June 7, 2010 and incorporated by reference herein.
3.1	Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated February 8, 2006 and filed on February 14, 2006 and incorporated by reference herein.
3.2	Articles of Amendment to the Third Amended and Restated Articles of Incorporation of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 30, 2007 and filed on September 5, 2007 and incorporated by reference herein.
3.3	Second Amended and Restated Bylaws of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated March 4, 2009 and filed on March 6, 2009 and incorporated by reference herein.
3.4	Statement of Designation of Series A-1 7.0% Cumulative Convertible Perpetual Preferred Stock of EXCO Resources, Inc., 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.

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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 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 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 Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
3.8	Statement of Designation of Series A-1 Hybrid Preferred Stock of EXCO Resources, Inc., 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.
3.9	Statement of Designation of Series A-2 Hybrid Preferred Stock of EXCO Resources, Inc., 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.
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-1 (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-1 (File No. 333-129935) filed on January 6, 2006 and incorporated by reference herein.
10.1	Underwriting Agreement, dated September 10, 2010, by and among EXCO Resources, Inc., certain of its subsidiaries, and J.P. Morgan Securities LLC, on behalf of itself and the other underwriters listed on Schedule 1 thereto, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated September 10, 2010 and filed on September 15, 2010 and incorporated by reference herein.
10.2	Amended and Restated 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.3	Form of Incentive Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.4	Form of Nonqualified Stock Option Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.*
10.5	Form of Restricted Stock Award Agreement for the EXCO Resources, Inc. 2005 Long-Term Incentive Plan, filed as an Exhibit to EXCO’s Registration Statement on Form S-8 (File No. 333-132551) filed on March 17, 2006 and incorporated by reference herein.*

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10.6	Third Amended and Restated EXCO Resources, Inc. Severance 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.*
10.7	Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated November 14, 2007 and filed on November 16, 2007 and incorporated by reference herein.
10.8	Amendment Number One to the Amended and Restated 2007 Director Plan of EXCO Resources, Inc., filed as an Exhibit to EXCO’s Annual Report on Form 10-K for 2009 filed February 24, 2010 and incorporated herein by reference.
10.9	Letter Agreement, dated March 28, 2007, with OCM Principal Opportunities Fund IV, L.P. and OCM EXCO Holdings, LLC, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
10.10	Letter Agreement, dated March 28, 2007, with Ares Corporate Opportunities Fund, ACOF EXCO, L.P., ACOF EXCO 892 Investors, L.P., Ares Corporate Opportunities Fund II, L.P., Ares EXCO, L.P. and Ares EXCO 892 Investors, L.P, filed as an Exhibit to EXCO’s Form 8-K dated March 28, 2007 and filed on April 2, 2007 and incorporated by reference herein.
10.11	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Operating Company, LP, as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.12	Purchase and Sale Agreement, dated June 28, 2009, by and between EXCO Resources, Inc., as seller, and Encore Operating, LP, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.13	Purchase and Sale Agreement, dated June 29, 2009, by and among EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.14	Amendment Number One to the EXCO Resources, Inc. Amended and Restated 2005 Long-Term Incentive Plan, filed as an exhibit to EXCO’s Current Report on Form 8-K, dated June 4, 2009 and filed on June 10, 2009 and incorporated by reference herein.
10.15	Joint Development Agreement, dated August 14, 2009, by and among BG US Production Company, LLC, EXCO Operating Company, LP and EXCO Production Company, LP, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 11, 2009 and filed on August 17, 2009 and incorporated by reference herein.
10.16	Contribution Agreement, dated August 5, 2009, by and among Vaughan Holding Company, LLC, EXCO Operating Company, LP and BG US Gathering Company, LLC, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.
10.17	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.
10.18	First Amendment, dated July 13, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on August 6, 2009 and incorporated by reference herein.
10.19	Second Amendment, dated August 5, 2009, to Purchase and Sale Agreement by and between EXCO Operating Company, LP and EXCO Production Company, LP, as sellers, and BG US Production Company, LLC, as buyer, filed as an Exhibit to EXCO’s Current Report on Form 8-K, dated August 5, 2009 and filed on August 11, 2009 and incorporated by reference herein.

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10.20	Purchase and Sale Agreement, dated September 29, 2009, by and between EXCO – North Coast Energy, Inc., Inc., as seller, and EnerVest Energy Institutional Fund XI-A, L.P., EnerVest Energy Institutional Fund XI-WI, L.P., and EV Properties, L.P., as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
10.21	Purchase and Sale Agreement, dated September 30, 2009, by and between EXCO Resources, Inc., as seller, and Sheridan Holding Company I, LLC, as buyer, filed as an exhibit to EXCO’s Quarterly Report on Form 10-Q, filed on November 4, 2009 and incorporated by reference herein.
10.22	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.
10.23	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.
10.24	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.
10.25	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.
10.26	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.
10.27	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.
10.28	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.
10.29	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.
10.30	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.

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10.31	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.
10.32	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.
10.33	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.
31.1	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer of EXCO Resources, Inc., filed herewith.
31.2	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Chief Financial Officer of EXCO Resources, Inc., filed herewith.
32.1	Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Chief Executive Officer and Chief Financial Officer of EXCO Resources, Inc., filed herewith.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Definition Linkbase Document
101.LAB**	XBRL Taxonomy Label Linkbase Document
101.PRE**	XBRL Taxonomy Presentation Linkbase Document

* These exhibits are management contracts.

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

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