Exco Resources (EXCO) 8-K Results of Operations and Financial Condition

Exhibit 99.1

	EXCO Resources, Inc.
	12377 Merit Drive, Suite 1700, LB 82, Dallas, Texas 75251
	(214) 368-2084            FAX (972) 367-3559

EXCO RESOURCES, INC. REPORTS FOURTH QUARTER AND

FULL YEAR 2010 RESULTS

DALLAS, TEXAS, February 23, 2011 …EXCO Resources, Inc. (NYSE: XCO) today announced fourth quarter and full year results for 2010.

Our fourth quarter and full year 2010 operating and financial results were driven by the continued success in developing our assets and managing our balance sheet. We have grown our reserves, acreage and production through both drilling and acquisitions. As a result of our Appalachia joint venture with BG Group in June 2010, we have positioned ourselves to accelerate our development and appraisal programs in Appalachia during 2011. While our capital expenditures are increasing, our expected cash flows together with available borrowing capacity under our credit agreement will provide funding for our programs. On January 24, 2011, we issued a press release containing our fourth quarter and full year 2010 operations update. Our significant financial results follow:

• Adjusted net earnings, a non-GAAP measure adjusting for non-cash derivative losses, gains on divestitures, costs we have incurred in connection with a buyout proposal received from our Chairman and Chief Executive Officer and items typically not included by securities analysts in published estimates, were earnings of $0.11 per share for the fourth quarter and $0.64 per share for the full year.

• Our GAAP results were a net loss of $0.34 per share for the fourth quarter and net income of $3.11 per diluted share for the full year. The fourth quarter GAAP loss reflects adjustments to the previously recognized gains for estimated post-closing adjustments associated with our Appalachia joint venture with BG Group.

• Oil and natural gas revenues for the fourth quarter were $135 million, exclusive of derivative financial instrument activities (derivatives) and $186 million inclusive of cash settlements of derivatives. Oil and natural gas revenues for the full year were $515 million, exclusive of derivatives, and $733 million inclusive of cash settlements from derivatives.

• The average daily oil and natural gas production for the fourth quarter was 350 Mmcfe per day. The fourth quarter production of 350 Mmcfe per day represented a 70% increase from pro forma fourth quarter 2009 production of 206 Mmcfe per day, which reflects the impact of our successful Haynesville shale drilling program. During the fourth quarter, production was impacted by approximately 21 Mmcfe per day due to shut-in producing wells as we drilled and completed offset wells. Oil and natural gas production was 112 Bcfe for the full year, or 307 Mmcfe per day.

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• Adjusted earnings before interest, taxes, depreciation, depletion and amortization and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the fourth quarter was $114 million, while the full year adjusted EBITDA was $478 million.

Douglas H. Miller, EXCO’s Chief Executive Officer commented “2010 was another significant year of achievement for EXCO. We increased our daily production from approximately 212 Mmcfe per day at the beginning of 2010 to approximately 385 Mmcfe per day at year end, effectively replacing all of the production we sold in 2009. We continued our success in the Haynesville shale play, entered into a joint venture with BG Group in Appalachia, and began ramping up our Appalachia activity. We also increased our Proved Reserves during 2010 by over 50%. Significant growth is expected to continue during 2011 with a projected daily exit rate of more than 600 Mmcfe per day. Our substantial inventory of undrilled locations in all of our operating areas will be very important to our operations in the future. ”

Net income

Our reported net income shown below, a GAAP measure, includes certain items not typically included by securities analysts in their published estimates of financial results. The following table provides a reconciliation of our net income to non-GAAP measures of adjusted net income:

	Three months ended												Twelve months ended
	December 31, 2010						December 31, 2009						December 31, 2010						December 31, 2009
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	(72,851	)				$	241,469					$	671,926					$	(496,804	)
Adjustments:
Non-cash mark-to-market losses on derivative financial instruments, before taxes		60,344						93,581						68,921						238,577
Non-cash write down of oil and natural gas properties		—						—						—						1,293,579
(Gain) loss on divestitures and non-recurring other operating items (1)		54,912						(221,735	)					(513,524	)					(682,361	)
Income taxes on above adjustments (2)		(46,103	)					51,262						177,841						(347,714	)
Adjustment to deferred tax asset valuation allowance (3)		27,977						(102,402	)					(267,805	)					200,817
Total adjustments, net of taxes		97,130						(179,294	)					(534,567	)					702,898
Adjusted net income	$	24,279					$	62,175					$	137,359					$	206,094
Net income (loss), GAAP (4)		(72,851	)	$	(0.34	)		241,469		$	1.14			671,926		$	3.16			(496,804	)	$	(2.35	)
Adjustments shown above (4)		97,130			0.46			(179,294	)		(0.85	)		(534,567	)		(2.51	)		702,898			3.33
Adjusted net income		24,279						62,175						137,359						206,094
Dilution attributable to stock options (5)		—			(0.01	)		—			—			—			(0.01	)		—			—
Adjusted net income for diluted earnings per share	$	24,279		$	0.11		$	62,175		$	0.29		$	137,359		$	0.64		$	206,094		$	0.98
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding		212,791						211,707						212,465						211,266
Dilutive stock options		3,334						2,846						3,270						—
Shares used to compute diluted EPS for adjusted net income		216,125						214,553						215,735						211,266

(1) The three months ended December 31, 2010 includes a $45 million adjustment to the previously recognized gain associated with our Appalachia joint venture and $5 million of costs we have incurred in connection with our special board committee’s evaluation of a proposal from our Chairman and Chief Executive Officer to purchase all of our outstanding stock not already owned by him. The full year 2010 includes an adjusted gain of $529 million from the Appalachia joint venture.

(2) The assumed income tax rate is 40% for all periods.

(3) Deferred tax valuation allowance has been adjusted to reflect impacts of adjustments.

(4) Per share amounts are based on weighted average number of common shares outstanding.

(5) Represents dilution per share attributable to common stock equivalents from in-the-money stock options.

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Cash flow and financing transactions

Our cash flow from operations before working capital changes was $106 million for the fourth quarter and $434 million for the full year. During 2010, we utilized our cash flow, credit agreement and proceeds from the Appalachia joint venture with BG Group to fund drilling and development programs. In addition, we issued $750 million of senior notes in September 2010 and used the proceeds to redeem our $445 million of outstanding senior notes and increase our liquidity.

	Three months ended							Twelve months ended
	December 31,				% change			December 31,					% change
(in thousands)	2010		2009					2010			2009
Cash flow from operations, GAAP	$	63,925	$	83,748				$	339,921		$	433,605
Net change in working capital		33,329		17,796					79,499			13,277
Non-recurring other operating items		9,050		9,571					15,364			9,571
Settlements of derivative financial instruments with a financing element		—		41,170					(907	)		182,952
Cash flow from operations before changes in working capital, non-GAAP measure (1) (2)	$	106,304	$	152,285		-30	%	$	433,877		$	639,405		-32	%

(1) Cash flow from operations before working capital changes, non-recurring other operating items and adjustments for settlements of derivative financial instruments with a financing element are presented because management believes it is a useful financial indicator for companies in our industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company’s ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. Operating cash flow is not a measure of financial performance pursuant to GAAP and should not be used as an alternative to cash flows from operating, investing, or financing activities. We have also elected to exclude the adjustment for derivative financial instruments with a financing element as this adjustment simply reclassifies settlements from operating cash flows to financing activities. Management believes these settlements should be included in this non-GAAP measure to conform to the intended measure of our ability to generate cash to fund operations and development activities. Non-recurring other operating items have been excluded as they do not reflect our on-going operating activities.

(2) Comparability between years is affected by the impacts of significant asset divestitures in 2009.

Proved Reserves

Our estimated proved reserves grew by 56%, from 959 Bcfe at December 31, 2009 to approximately 1.5 Tcfe at December 31, 2010, calculated pursuant to SEC pricing rules, which are based on the simple average of the first of the month reference natural gas and oil prices for the prior twelve month period, adjusted for energy content, quality and basis differentials. For 2010, the reference price was $4.38 per Mmbtu for natural gas and $79.43 per Bbl for oil which resulted in an adjusted price of $4.37 per Mmbtu for natural gas and $75.83 per Bbl for oil. Our PV-10, a non-GAAP measure, and standardized measure using the SEC pricing adjusted for differentials were $1.4 billion and $1.2 billion, respectively. The following table presents the details of changes in our proved reserves:

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	Oil (Mbbls)			Natural gas (Mmcfe)			Equivalent natural gas (Mmcfe)
Proved developed		4,633			793,777			821,575
Proved undeveloped		2,725			661,176			677,526
Total		7,358			1,454,953			1,499,101
The changes in reserves for the year are as follows:
December 31, 2009		5,518			925,728			958,836
Purchase of reserves in place		—			30,047			30,047
Extensions and discoveries		1,631			635,841			645,627
Revisions of previous estimates:
Changes in price		751			48,630			53,136
Changes in performance		549			63,089			66,383
Sales of reserves in place		(403	)		(140,504	)		(142,922	)
Production		(688	)		(107,878	)		(112,006	)
December 31, 2010		7,358			1,454,953			1,499,101

Using the five year futures strip price at December 31, 2010 averaging $5.23 per Mmbtu for natural gas and $93.09 per Bbl of oil, as adjusted for energy content, quality and basis differentials, our estimated proved reserves would have been 1.6 Tcfe. Pro forma for the Chief acquisition that closed on January 11, 2011 and a pending Appalachian acquisition that is projected to close in March 2011, we estimate our total net resource potential to be approximately 13.0 Tcfe.

We replaced 576% of our production with a finding and development cost of $0.54 per Mcfe through the drill bit. Adjusting for the benefit of $351 million of BG carry, our “all-in” finding and development cost would have been $1.03 per Mcfe. Our development drilling success has given us the ability to book proved reserves on 80-acre spacing in our core DeSoto Parish Haynesville shale development area.

Development and Exploitation Activity

We drilled and completed 51 gross (31.0 net) operated wells in the fourth quarter 2010 and 154 gross (93.7 net) operated wells during full year 2010. Including the wells we own interests in that were operated by others, we drilled and completed 68 gross (32.1 net) wells in the fourth quarter 2010 and we drilled and completed 205 gross (97.2 net) wells during full year 2010. During the fourth quarter 2010, we had a 100% drilling success rate, while for full year 2010, we realized a 99% drilling success rate as we completed 205 of the 207 wells that we drilled.

Our capital expenditures, including our development, leasing, and other corporate activity, totaled $132 million and $503 million for fourth quarter 2010 and full year 2010, respectively. In addition, we contributed $144 million to our midstream entities development program.

Our capital budget for 2011 totals $976 million. Approximately $769 million of this budget will fund the drilling and completion of 369 gross wells. Approximately 89% of our 2011 capital budget is allocated to our Haynesville/Bossier and Marcellus shale programs. Highlights of our 2011 capital budget program follow.

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East Texas/North Louisiana

Our budgeted capital expenditures in this area total $782 million, of which $683 million are allocated for drilling and completion of 233 gross (65.2 net) horizontal shale wells, all of which are within our EXCO/BG Group joint venture area. We will operate 163 of the 233 gross wells. We plan to run 22 operated drilling rigs throughout full year 2011 to implement this drilling and completion program which will be focused in our DeSoto Parish area of northwest Louisiana and in our Shelby Trough area of East Texas. In the DeSoto Parish area, we will run 16 operated drilling rigs as we implement a full development program, drilling on 80-acre spacing from pads within our operated units. In the Shelby Trough area, we will drill using six operated rigs as we delineate and hold our acreage acquired during 2010. We plan to move to full development of the Shelby Trough area acreage during 2012.

Appalachia

We plan to spend $83 million of capital within our Appalachian region during 2011. Of this total, approximately $38 million will be allocated to drilling and completion of 64 gross (23.9 net) operated wells. Of the 64 wells, 52 will be development wells (within our recently acquired acreage in northeast Pennsylvania and our acreage in west central Pennsylvania) and 12 will be appraisal wells (primarily in central Pennsylvania). This drilling will be within the EXCO/BG Group Appalachia joint venture area, so our net drilling dollars are reduced by the effect of the carry we receive from BG Group per the terms of our joint venture. As of early 2011, approximately $126 million of carry dollars remain available to us from BG Group. We will drill with two operated drilling rigs early in 2011, and plan to exit 2011 with four to five operated drilling rigs in Appalachia.

Permian

Our Permian Canyon Sand field development continues. We will use two operated drilling rigs and spend $48 million of the total $53 million capital budget allocated to the Permian area to drill and complete 72 gross (69.8 net) wells during 2011. As this development program contains a significant amount of oil production, our rates of return for this drilling and completion program typically exceed 60%.

Midstream

Through our jointly held midstream company, TGGT, we are constructing a major expansion in our Shelby Trough area of East Texas. We are also continuing to develop our gathering and treating capacity in the DeSoto Parish area of northwest Louisiana. TGGT recently closed a $500 million credit agreement which, combined with internally generated cash flow, will fund its capital program. At the closing of the credit agreement, TGGT funded a distribution to its owners, of which $125 million was distributed to us.

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Financial Data

Our consolidated balance sheets as of December 31, 2010 and 2009 and consolidated statements of operations for the three months and years ended December 31, 2010 and 2009, and consolidated statements of cash flows for the years ended December 31, 2010 and 2009, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release which have not been previously reconciled.

EXCO will host a conference call on Thursday, February 24, 2011 at 9:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call (800) 309-5788 if you wish to participate, and ask for the EXCO conference call ID# 43614912. The conference call will also be webcast on EXCO’s website atwww.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted on EXCO’s website on Wednesday, February 23, 2011, after market close.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., March 10, 2011. Please call (800) 642-1687 and enter conference ID# 43614912 to hear the recording. A digital recording of the conference call will also be available on EXCO’s website.

Additional information about EXCO Resources, Inc. may be obtained by contacting EXCO’s Chairman, Douglas H. Miller, or its President, Stephen F. Smith, at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting EXCO’s website atwww.excoresources.com. EXCO’s SEC filings and press releases can be found under the Investor Relations tab.

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We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned 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 presentation, and the risk factors included in the Annual Report on Form 10-K, as amended, for the year ended December 31, 2009 and after February 24, 2011, our Annual Report on Form 10-K for the year ended December 31, 2010, and our other periodic filings with the SEC.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

The SEC permits oil and natural gas companies in filings made with the SEC to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Beginning with reserves reported for the year ended December 31, 2009, the SEC permits optional disclosure of “probable” and “possible” reserves in its filings with the SEC. EXCO may use

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broader terms to describe additional reserve opportunities such as “potential,” “unproved,” or “unbooked potential,” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially greater risk of being actually realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2009 and after February 24, 2011, our Annual Report on Form 10-K for the year ended December 31, 2010, which are available on our website at www.excoresources.com under the Investor Relations tab.

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EXCO Resources, Inc.

Consolidated balance sheet

	December 31,
(in thousands)	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	44,229		$	68,407
Restricted cash		161,717			58,909
Accounts receivable, net:
Oil and natural gas		80,740			56,485
Joint interest		104,358			47,104
Interest and other		35,594			10,832
Inventory		7,876			15,830
Derivative financial instruments		73,176			138,120
Other		12,770			6,401
Total current assets		520,460			402,088
Equity investments		379,001			216,987
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		599,409			492,882
Proved developed and undeveloped oil and natural gas properties		2,370,962			1,875,749
Accumulated depletion		(1,312,216	)		(1,132,604	)
Oil and natural gas properties, net		1,658,155			1,236,027
Gas gathering assets		157,929			180,506
Accumulated depreciation and amortization		(24,772	)		(22,841	)
Gas gathering assets, net		133,157			157,665
Office, field and other equipment, net		43,149			31,771
Deferred financing costs, net		30,704			7,602
Derivative financial instruments		23,722			34,677
Goodwill		218,256			269,656
Deposits on acquisitions		464,151			—
Other assets		6,665			2,421
Total assets	$	3,477,420		$	2,358,894

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EXCO Resources, Inc.

Consolidated balance sheet

	December 31,
(in thousands, except per share and share data)	2010			2009
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	152,999		$	112,991
Revenues and royalties payable		108,830			79,356
Accrued interest payable		18,983			16,193
Current portion of asset retirement obligations		900			900
Income taxes payable		211			210
Derivative financial instruments		3,775			3,264
Total current liabilities		285,698			212,914
Long-term debt, net of current maturities		1,588,269			1,196,277
Deferred income taxes		—			—
Derivative financial instruments		4,200			11,688
Asset retirement obligations and other long-term liabilities		58,701			78,427
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding		—			—
Common stock, $0.001 par value; 350,000,000 authorized shares; 213,736,266 shares issued and 213,197,045 shares outstanding at December 31, 2010; 211,905,509 shares issued and outstanding at December 31, 2009		214			212
Additional paid-in capital		3,151,513			3,105,238
Accumulated deficit		(1,603,696	)		(2,245,862	)
Treasury stock, at cost; 539,221 shares at December 31, 2010		(7,479	)		—
Total shareholders’ equity		1,540,552			859,588
Total liabilities and shareholders’ equity	$	3,477,420		$	2,358,894

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EXCO Resources, Inc.

Consolidated statement of operations

	Three months ended December 31,						Year ended December 31,
(in thousands, except per share data)	2010			2009			2010			2009
Revenues:
Oil and natural gas	$	134,898		$	106,552		$	515,226		$	550,505
Midstream		—			—			—			35,330
Total revenues		134,898			106,552			515,226			585,835
Costs and expenses:
Oil and natural gas production		24,962			33,091			108,184			177,629
Midstream operating		—			—			—			35,580
Gathering and transportation		19,330			6,081			54,877			18,960
Depreciation, depletion and amortization		59,119			33,755			196,963			221,438
Write-down of oil and natural gas properties		—			—			—			1,293,579
Accretion of discount on asset retirement obligations		838			1,276			3,758			7,132
General and administrative		28,795			34,495			105,114			99,177
(Gain) loss on divestitures and other operating items		59,224			(223,770	)		(509,872	)		(676,434	)
Total costs and expenses		192,268			(115,072	)		(40,976	)		1,177,061
Operating income (loss)		(57,370	)		221,624			556,202			(591,226	)
Other income (expense):
Interest expense		(11,983	)		(17,401	)		(45,533	)		(147,161	)
Gain (loss) on derivative financial instruments		(9,549	)		27,140			146,516			232,025
Equity income (loss)		3,968			59			16,022			(69	)
Other income (expense)		143			357			327			126
Total other income (expense)		(17,421	)		10,155			117,332			84,921
Income (loss) before income taxes		(74,791	)		231,779			673,534			(506,305	)
Income tax expense (benefit)		(1,940	)		(9,690	)		1,608			(9,501	)
Net income (loss)	$	(72,851	)	$	241,469		$	671,926		$	(496,804	)
Earnings (loss) per common share:
Basic
Net income (loss)	$	(0.34	)	$	1.14		$	3.16		$	(2.35	)
Weighted average common shares outstanding		212,791			211,707			212,465			211,266
Diluted
Net income (loss)	$	(0.34	)	$	1.13		$	3.11		$	(2.35	)
Weighted average common and common equivalent shares outstanding		212,791			214,553			215,735			211,266

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EXCO Resources, Inc.

Consolidated statement of cash flows

	Year ended December 31,
(in thousands)	2010			2009
Operating Activities:
Net income (loss)	$	671,926		$	(496,804	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		196,963			221,438
Stock option compensation expense		16,841			18,987
Accretion of discount on asset retirement obligations		3,758			7,132
Write-down of oil and natural gas properties		—			1,293,579
Gain on divestitures		(528,888	)		(691,932	)
(Income) loss from equity investments		(16,022	)		69
Non-cash change in fair value of derivatives		68,921			238,577
Cash settlements of assumed derivatives		907			(182,952	)
Deferred income taxes		—			(9,371	)
Amortization of deferred financing costs, discount on the 2018 Notes and premium on the 2011 Notes		5,014			48,159
Effect of changes in:
Accounts receivable		(136,417	)		34,998
Other current assets		1,188			(2,325	)
Accounts payable and other current liabilities		55,730			(45,950	)
Net cash provided by operating activities		339,921			433,605
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(519,206	)		(664,292	)
Property acquisitions		(522,765	)		(68,404	)
Restricted cash		(102,808	)		(58,909	)
Deposits on acquisitions		(464,151	)		—
Investment in equity investments		(143,740	)		(47,500	)
Proceeds from disposition of property and equipment		1,044,833			2,074,380
Advances to Appalachia JV		(5,017	)		—
Net cash provided by (used in) investing activities		(712,854	)		1,235,275
Financing Activities:
Borrowings under credit agreements		2,072,399			247,799
Repayments under credit agreements		(1,970,963	)		(2,067,671	)
Proceeds from issuance of 2018 Notes		738,975			—
Repayment of 2011 Notes		(444,720	)		—
Proceeds from issuance of common stock		23,024			10,361
Payment of common stock dividends		(29,760	)		(10,582	)
Payment for common stock repurchased		(7,479	)		—
Settlements of derivative financial instruments with a financing element		(907	)		182,952
Deferred financing costs and other		(31,814	)		(20,471	)
Net cash provided by (used in) financing activities		348,755			(1,657,612	)
Net increase (decrease) in cash		(24,178	)		11,268
Cash at beginning of period		68,407			57,139
Cash at end of period	$	44,229		$	68,407
Supplemental Cash Flow Information:
Cash interest payments	$	54,523		$	112,560
Income tax payments	$	5,460		$	—
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	6,351		$	5,066
Capitalized interest	$	20,829		$	5,840
Issuance of common stock for director services	$	61		$	59

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EXCO Resources, Inc.

Consolidated EBITDA

And adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)

	Three months ended December 31,						Twelve months ended December 31,
(in thousands)	2010			2009			2010			2009
Net income (loss)	$	(72,851	)	$	241,469		$	671,926		$	(496,804	)
Interest expense		11,983			17,401			45,533			147,161
Income tax expense (benefit)		(1,940	)		(9,690	)		1,608			(9,501	)
Depreciation, depletion and amortization		59,119			33,755			196,963			221,438
EBITDA(1)		(3,689	)		282,935			916,030			(137,706	)
Accretion of discount on asset retirement obligations		838			1,276			3,758			7,132
Non-cash write-down of oil and natural gas properties		—			—			—			1,293,579
(Gain) loss on divestitures and non-recurring other operating items		54,912			(221,735	)		(513,524	)		(682,361	)
Equity method income		(3,968	)		(357	)		(16,022	)		69
Non-cash change in fair value of oil and natural gas derivative financial instruments		60,344			97,192			70,939			246,438
Stock based compensation expense		5,973			9,124			16,841			18,987
Adjusted EBITDA(1)	$	114,410		$	168,435		$	478,022		$	746,138
Interest expense (2)		(11,983	)		(21,012	)		(47,551	)		(155,022	)
Income tax benefit (expense)		1,940			9,690			(1,608	)		9,501
Amortization of deferred financing costs, premium on 2011 Notes and discount on 2018 Notes		1,937			3,832			5,014			48,159
Deferred income taxes		—			(8,660	)		—			(9,371	)
Non-recurring other operating items		(9,050	)		(9,571	)		(15,364	)		(9,571	)
Changes in operating assets and liabilities and other		(33,329	)		(17,796	)		(79,499	)		(13,277	)
Settlements of derivative financial instruments with a financing element		—			(41,170	)		907			(182,952	)
					��
Net cash provided by operating activities	$	63,925		$	83,748		$	339,921		$	433,605

	Three months ended December 31,						Twelve months ended December 31,
(in thousands)	2010			2009			2010			2009
Statement of cash flow data:
Cash flow provided by (used in):
Operating activities	$	63,925		$	83,748		$	339,921		$	433,605
Investing activities		(668,691	)		385,513			(712,854	)		1,235,275
Financing activities		597,871			(456,535	)		348,755			(1,657,612	)
Other financial and operating data:
EBITDA(1)		(3,689	)		282,935			916,030			(137,706	)
Adjusted EBITDA(1)		114,410			168,435			478,022			746,138

(1) Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude non-cash write-downs of oil and natural gas properties, gains on divestitures and non-recurring other operating items, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, stock-based compensation and income or losses from equity method investments. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, these measures are used in covenant calculations required under our credit agreement and the indenture governing our 7.5% senior notes due September 15, 2018. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to us. Our computations of

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EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures.

(2) Excludes non-cash changes in fair value of $0 and $3.6 million for the three months ended December 31, 2010 and 2009, respectively, and $2.0 million and $7.9 million for the twelve months ended December 31, 2010 and 2009, respectively, for interest rate swaps included in GAAP interest expense.

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EXCO Resources, Inc.

Summary of operating data

	Three months ended							Twelve months ended
	December 31,				%			December 31,				%
	2010		2009		Change			2010		2009		Change
Production:
Oil (Mbbls)		183		204		-10	%		688		1,571		-56	%
Natural gas (Mmcf)		31,094		22,138		40	%		107,878		118,736		-9	%
Oil and natural gas (Mmcfe)		32,192		23,362		38	%		112,006		128,162		-13	%
Average sales prices (before derivativefinancial instrument activities):
Oil (per Bbl)	$	81.83	$	72.68		13	%	$	76.18	$	53.72		42	%
Natural gas (per Mcf)		3.86		4.14		-7	%		4.29		3.93		9	%
Total production (per Mcfe)		4.19		4.56		-8	%		4.60		4.30		7	%
Average costs (per Mcfe):
Oil and natural gas operating costs	$	0.63	$	1.14		-45	%	$	0.75	$	1.08		-31	%
Production and ad valorem taxes		0.14		0.28		-50	%		0.21		0.30		-30	%
Gathering and transportation		0.60		0.26		131	%		0.49		0.15		227	%
Depletion		1.69		1.23		37	%		1.60		1.53		5	%
Depreciation and amortization		0.14		0.22		-36	%		0.15		0.19		-21	%
General and adminstrative		0.89		1.48		-40	%		0.94		0.77		22	%

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