Exco Resources (EXCO) 8-K Exco Resources, Inc. Reports Third Quarter 2011 Results

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 THIRD QUARTER 2011 RESULTS

DALLAS, TEXAS, November 1, 2011…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced third quarter results for 2011.

– Adjusted net earnings, a non-GAAP measure adjusting for non-cash gains and losses from derivative financial instruments (derivatives), gains on divestitures, asset impairments, costs incurred in connection with our special committee’s review of strategic alternatives and items typically not included by securities analysts in published estimates, were $0.15 per share for the third quarter 2011 compared to $0.18 per share for the second quarter 2011 and $0.16 per share for the third quarter 2010.

– GAAP results were net income of $0.39 per diluted share for the third quarter 2011 compared with net income of $0.38 per diluted share for the second quarter 2011. Net income was $0.30 per diluted share for the third quarter 2010.

– Oil and natural gas production was 50 Bcfe, or 540 Mmcfe per day, for the third quarter 2011 compared with 46 Bcfe, or 500 Mmcfe per day, in the second quarter 2011. Production was 29 Bcfe, or 320 Mmcfe per day, in the third quarter 2010. The increase in the year-over-year quarterly production is primarily attributable to increased production volumes in our Haynesville/Bossier shale play, where third quarter 2011 volumes were 37 Bcfe, or 401 Mmcfe per day, compared with 16 Bcfe, or 173 Mmcfe per day, in the third quarter 2010, an increase of 132%. The increased production during the third quarter was reduced by approximately 44 Mmcf per day as a result of a May 28, 2011 incident at a TGGT treating facility which resulted in curtailment of certain North Louisiana production volumes. We expect this level of curtailment of certain volumes to continue through the end of the fourth quarter 2011.

– Oil and natural gas revenues for the third quarter 2011 were $207 million, unchanged from the second quarter 2011. The third quarter 2010 oil and natural gas revenues were $131 million. The higher year-over-year revenues reflect the favorable impacts of our increased production which was partially offset by a 6% decrease in the average sales price per Mcfe. When the impacts of cash settlements from our oil and natural gas derivatives are considered, oil and natural gas revenues were $240 million for the third quarter 2011 compared with $230 million for the second quarter 2011 and $174 million for the third quarter 2010.

1

– Oil and natural gas operating costs for the third quarter 2011 were $0.42 per Mcfe compared to $0.75 per Mcfe for the third quarter 2010. This 44% reduction in per unit operating costs reflects the significant impact of increased volumes from our horizontal Haynesville/Bossier shale wells, which produce high volumes of natural gas and have low per well operating expenses.

– 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 third quarter 2011 was $163 million compared with $116 million in the third quarter 2010.

– Cash flow from operations before changes in working capital, a non-GAAP measure, was $151 million for the three months ended September 30, 2011 compared with $108 million for the three months ended September 30, 2010, an increase of 40%.

Douglas H. Miller, EXCO’s Chief Executive Officer commented “Our results for the third quarter 2011 reflect our focus on well performance, capital and operating costs. Production grew 69% from the prior year despite curtailments, and we remain on track to exit 2011 at nearly 600 Mmcfe per day of net production. Our direct operating costs during the quarter decreased by 44% from the prior year to $0.42 per Mcfe, reflecting the high quality of our asset base. In DeSoto Parish, we continue to refine our production techniques and have successfully reduced our drilling and completion costs during the year. In our Shelby area, we are focused on further delineation in both the Haynesville and Bossier shales where recent IP’s were in excess of 27 Mmcf per day. Our drilling days have shown a marked improvement during the year resulting in reduced drilling costs. Results in our Marcellus acreage during the quarter have also seen improvements. During the third quarter, we turned 11 Marcellus wells to sales with an average IP rate of 5.8 Mmcf per day. As we begin our development program in the Marcellus, we are realizing reductions in our average well cost and expect further reductions as a result of drilling and completion efficiencies and building our water infrastructure. We are currently in the process of finalizing our 2012 capital budget. Although the low cost, high volume nature of our operations results in a satisfactory rate of return in the current natural gas environment, we are evaluating the appropriate level of our 2012 development activities.”

2

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						Three months ended						Nine months ended						Nine months ended
	September 30, 2011						September 30, 2010						September 30, 2011						September 30, 2010
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	84,945					$	64,896					$	189,248					$	744,777
Adjustments:
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes		(51,346	)					(13,134	)					(47,888	)					8,577
Gains from early termination of derivative financial instruments		—						—						—						(37,936	)
(Gain) loss on divestitures and non-recurring other operating items (1)		21,587						6,442						27,542						(568,436	)
Income taxes on above adjustments (2)		11,904						2,677						8,139						239,118
Adjustment to deferred tax asset valuation allowance (3)		(33,978	)					(26,501	)					(75,699	)					(295,782	)
Total adjustments, net of taxes		(51,833	)					(30,516	)					(87,906	)					(654,459	)
Adjusted net income	$	33,112					$	34,380					$	101,342					$	90,318
Net income (loss), GAAP (4)	$	84,945		$	0.40		$	64,896		$	0.31		$	189,248		$	0.89		$	744,777		$	3.51
Adjustments shown above (4)		(51,833	)		(0.24	)		(30,516	)		(0.14	)		(87,906	)		(0.41	)		(654,459	)		(3.08	)
Dilution attributable to dilutive common stock equivalents (5)		—			(0.01	)		—			(0.01	)		—			(0.01	)		—			(0.01	)
Adjusted net income for diluted earnings per share	$	33,112		$	0.15		$	34,380		$	0.16		$	101,342		$	0.47		$	90,318		$	0.42
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding		214,068						212,480						213,831						212,356
Dilutive common stock equivalents		2,246						2,442						3,336						3,271
Shares used to compute diluted EPS for adjusted net income		216,314						214,922						217,167						215,627

(1) Costs primarily associated with litigation reserves, our special committee’s review of strategic alternatives, certain asset impairments and gains associated with formation of our Appalachia JV in June 2010.

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

(3) Deferred tax valuation allowance has been adjusted to reflect the assumed income tax rate of 40% for all periods.

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

(5) Represents dilution per share attributable to common stock equivalents.

Cash flow and financing transactions

Our cash flow from operations before working capital changes, a non-GAAP measure, was $151 million for the third quarter 2011. We use our cash flow and credit agreement to fund our drilling and development programs.

	Three months ended				Nine months ended
	September 30,				September 30,
(in thousands)	2011		2010		2011		2010
Cash flow from operations, GAAP	$	127,301	$	94,143	$	355,334	$	275,996
Net change in working capital		7,811		7,224		39,422		46,170
Gains from early termination of derivative financial instruments		—		—		—		(37,936	)
Non-recurring other operating items		15,858		6,314		21,813		6,314
Settlements of derivative financial instruments with a financing element		—		—		—		(907	)
Cash flow from operations before changes in working capital, non-GAAP measure (1)	$	150,970	$	107,681	$	416,569	$	289,637

(1) Cash flow from operations before working capital changes, non-recurring other operating items, early termination of derivatives 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 and early termination of derivatives have been excluded as they do not reflect our on-going operating activities.

3

Current liquidity

As of October 27, 2011, $1.0 billion was drawn under our credit agreement and we had $230.9 million of cash, which includes $152.5 million of restricted cash. Our available borrowing under our credit agreement as of October 27, 2011, including cash and restricted cash on hand was $688.9 million.

Operations activity and outlook

During the third quarter 2011, we spent $233 million on development and exploitation activities, drilling and completing 79 gross (41.2 net) operated wells, compared with 71 gross (40.6 net) operated wells during the second quarter 2011. In addition, we participated in 12 gross (0.3 net) wells operated by others (OBO) during the third quarter 2011. We had an overall drilling success rate of 100% for the third quarter 2011. Our total capital expenditures, including leasing and net of acreage reimbursements from BG Group, were approximately $263 million in the third quarter 2011. We are continuing efforts to opportunistically acquire additional leasehold in our core shale areas.

Our projected capital spending for 2011 is presented in the following table.

	1Q		2Q		3Q		October - December
	2011		2011		2011		2011 capital		Total 2011
(in thousands)	actuals		actuals		actuals		forecast		capital forecast
Capital expenditures:
Development capital expenditures	$	198,288	$	240,925	$	232,614	$	220,060	$	891,887
Lease purchases (1)		24,546		80		8,441		492		33,559
Seismic		4,447		979		2,534		4,733		12,693
Water pipelines and gas gathering		812		1,272		3,940		4,040		10,064
Corporate and other		17,518		17,182		15,878		15,650		66,228
Capital expenditures before acquisitions	$	245,611	$	260,438	$	263,407	$	244,975	$	1,014,431

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

During the third quarter 2011, we closed on $15.3 million of acquisitions, which were principally undeveloped Marcellus shale acreage in our Appalachian region.

Haynesville/Bossier Shale

Our horizontal Haynesville shale development program continues to yield outstanding results. As of October 16, 2011, our Haynesville/Bossier operated production was 1,243 Mmcf per day gross (395 Mmcf per day net) and with the addition of our OBO wells, we had 419 Mmcf per day of net production. We continue to focus our activities in two main development areas. Our development program in DeSoto Parish, Louisiana is focused on manufacturing on 80-acre spacing. Our program in San Augustine and Nacogdoches Counties, Texas is focused on delineation and testing of our acreage. We continue optimizing our operations with efforts to reduce costs and improve our estimated ultimate recoveries.

During 2011, we plan to drill 243 gross (70.7 net) wells in the Haynesville/Bossier shale play in East Texas/North Louisiana. Of these 243 wells, 173 gross wells are operated by EXCO. During the third quarter 2011, we drilled and completed 50 gross (19.7 net) operated horizontal Haynesville and Bossier wells and participated in 12 gross (0.3 net) OBO Haynesville horizontal wells. We utilized 22 operated rigs and spud 39 operated horizontal wells. In addition to our operated rig count, we typically have 3-6 OBO rigs drilling in the play. During the quarter, nine OBO wells were spud. We currently have 264 operated horizontal wells and 144 OBO horizontal wells flowing to sales.

4

The average initial production rate (“IP”) during the quarter from all of our operated Haynesville horizontal wells in DeSoto Parish was 18.9 Mmcf per day on a managed drawdown/restricted choke program. Our manufacturing approach for simultaneous drilling followed by simultaneous completions by unit is being successfully implemented. We currently have 19 units fully drilled, completed and flowing to sales on 80-acre spacing and expect to have 25 units fully developed by year end. During the course of 2011, our average well costs in DeSoto Parish have decreased from $9.9 million in the first half of 2011 to $9.6 million in the third quarter of 2011. These cost improvements include more efficient pad and road utilization and construction processes, drill bit design changes and more efficient completion design and implementation processes.

We acquired our Shelby area assets in May 2010 with total gross production of 34 Mmcf per day gross from eight operated wells. Our Shelby area is currently producing 224 Mmcf per day gross from 49 operated wells. Results from our testing and delineation program in this area are encouraging. During the third quarter 2011, we completed three Haynesville wells in the deeper part of the play in Nacogdoches County, Texas with average IP rates of 28 Mmcf per day with average flowing pressures of 10,300 psi on 26/64ths chokes. These wells are performing above our original expectations. The wells in this area are approximately 19,700 feet measured depth with an average completed lateral length of approximately 4,700 feet. We have made significant progress in 2011 in the drilling performance in the Nacogdoches County area of the play. Our initial wells in the first half of 2011 were averaging 63 days from spud to rig release and our most recent wells in the second half of 2011 are averaging 55 days, a 13% reduction in time. We drilled and completed our second horizontal Middle Bossier test well in the Shelby area during the third quarter 2011 with an IP rate of 27 Mmcf per day from a 13 stage fracture stimulation treatment. The Middle Bossier performance is also above our original expectations. We currently have a total of seven operated rigs running in the Shelby area.

Marcellus Shale

Our current gross operated Marcellus shale production is approximately 100 Mmcf per day, which represents an increase of more than 50% since the end of the second quarter 2011. We have implemented a development program within our acreage in northeast Pennsylvania and an appraisal program primarily in central Pennsylvania. We plan to drill 49 gross (16.0 net) operated wells in the Marcellus shale play in our Appalachia region during 2011. Of the 49 wells, 42 gross (12.8 net) will be development wells and 7 gross (3.2 net) will be appraisal wells. We are currently drilling with four operated rigs, three of which are in our northeast Pennsylvania development area. Our net drilling dollars are reduced by the effect of the carry we receive from BG Group. Approximately $78.8 million of the carry remains available to us from BG Group as of September 30, 2011. We expect that the remaining carry amount will be used in the first half of 2012.

5

We spud 12 new operated wells and drilled and completed 11 gross (4.0 net) operated wells during the third quarter 2011 in the Marcellus shale. In northeast Pennsylvania, we turned six wells on two pads to sales at the end of the quarter with an average IP rate of 6.4 Mmcf per day from an average lateral length of approximately 3,400 feet. In our central Pennsylvania area, we turned five wells to sales from two pads during the quarter with an average IP rate of 5.0 Mmcf per day from an average lateral length of approximately 4,100 feet. We are also focused on building our field infrastructure in support of our expected levels of activity. Along with efficiency gains derived from our drilling and completion program, these infrastructure investments are expected to be the primary drivers to reduce our average development well costs.

Permian

We drilled and completed 18 gross (17.5 net) wells in our Sugg Ranch area during the third quarter 2011 with 100% drilling success. We currently are running one operated rig and plan to drill 68 gross (65.4 net) wells in 2011. Our production at Sugg Ranch has increased by 8% in the third quarter of 2011 as compared to the third quarter of 2010, and economics for this drilling activity typically have rates-of-return in excess of 50%.

Midstream

Through our jointly held midstream company, TGGT, we continue pipeline expansion and treating facilities installation efforts in our Shelby Trough area of east Texas in order to meet the expected throughput volume increase. We are also continuing to provide timely well-hookups and increased treating capacity in the DeSoto Parish area of northwest Louisiana. Total throughput for TGGT averaged approximately 1.5 Bcf per day for the third quarter of 2011 compared with total average throughput of 1.4 Bcf per day in the second quarter 2011. Despite the volumetric reductions from the May 28, 2011 incident discussed below, our current throughput is approximately 1.6 Bcf per day.

In the second quarter 2011, an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana resulting in an immediate shut-down of the facility. As a precautionary measure, TGGT also shut down another amine treating facility located in DeSoto Parish with similar specifications, which was restarted in October 2011. TGGT is also installing temporary treating units and expects to be capable of treating all projected northwest Louisiana throughput volumes early in the first quarter of 2012 once these temporary treating units are operational. Restart of all treating activity has been delayed from the initial estimated timeline. Delays have resulted from the damage assessment of infrastructure and facilities and the related planning and execution of appropriate engineering and operational upgrades

The estimated third quarter 2011 impact to TGGT resulting from this incident was an $8.7 million net decrease to their operating income, which was primarily due to an estimated $7.0 million reduction in revenue. TGGT received an initial insurance reimbursement associated with the incident of approximately $6.2 million during the third quarter 2011. TGGT expects to have the damaged facility re-commissioned early in 2012.

6

Financial Data

Our consolidated balance sheets as of September 30, 2011 and December 31, 2010 and consolidated statements of operations for the three and nine months ended September 30, 2011 and 2010, and consolidated statements of cash flows for the nine months ended September 30, 2011 and 2010, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this release which have not been previously reconciled.

EXCO will host a conference call on Wednesday, November 2, 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# 16833223. 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 Tuesday, November 1, 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., November 16, 2011. Please call (800) 585-8367 or (855) 859-2056 and enter conference ID# 16833223 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.

###

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, 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.

7

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 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, 2010, which is available on our website at www.excoresources.com under the Investor Relations tab.

8

EXCO Resources, Inc.

Consolidated balance sheet

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

9

EXCO Resources, Inc.

Consolidated balance sheet

	September 30,			December 31,
(in thousands, except per share and share data)	2011			2010
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	173,196		$	152,999
Revenues and royalties payable		187,170			108,830
Accrued interest payable		3,855			18,983
Current portion of asset retirement obligations		1,279			900
Income taxes payable		—			211
Derivative financial instruments		—			3,775
Total current liabilities		365,500			285,698
Long-term debt		1,712,555			1,588,269
Deferred income taxes		—			—
Derivative financial instruments		578			4,200
Asset retirement obligations and other long-term liabilities		63,073			58,701
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; authorized shares - 10,000,000; issued and outstanding shares - 200,000 presented above none issued and outstanding		—			—
Common stock, $0.001 par value; 350,000,000 authorized shares; 215,310,953 shares issued and 214,771,732 shares outstanding at September 30, 2011; 213,736,266 shares issued and 213,197,045 shares outstanding at December 31, 2010		215			214
Additional paid-in capital		3,175,184			3,151,513
Accumulated deficit		(1,440,121	)		(1,603,696	)
Treasury stock, at cost; 539,221 shares at September 30, 2011 and December 31, 2010		(7,479	)		(7,479	)
Total shareholders’ equity		1,727,799			1,540,552
Total liabilities and shareholders’ equity	$	3,869,505		$	3,477,420

10

EXCO Resources, Inc.

Consolidated statement of operations

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

11

EXCO Resources, Inc.

Consolidated statement of cash flows

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

12

EXCO Resources, Inc.

Consolidated EBITDA

And adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)

		000000000			000000000			000000000			000000000
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Net income (loss)	$	84,945		$	64,896		$	189,248		$	744,777
Interest expense		15,090			8,440			43,585			33,550
Income tax expense (benefit)		—			(904	)		—			3,548
Depreciation, depletion and amortization		100,491			53,687			253,833			137,844
EBITDA(1)		200,526			126,119			486,666			919,719
Accretion of discount on asset retirement obligations		938			830			2,728			2,920
(Gain) loss on divestitures and non-recurring other operating items		21,587			6,442			27,542			(568,436	)
Equity method income		(10,666	)		(6,675	)		(22,749	)		(12,054	)
Non-cash change in fair value of derivative financial instruments		(51,346	)		(13,134	)		(47,888	)		10,595
Gain from early termination of derivative financial instruments		—			—			—			(37,936	)
Stock based compensation expense		2,450			2,405			7,537			10,868
Adjusted EBITDA (1)	$	163,489		$	115,987		$	453,836		$	325,676
Interest expense (2)		(15,090	)		(8,440	)		(43,585	)		(35,568	)
Income taxes		—			904			—			(3,548	)
Amortization of deferred financing costs, premium on the 2011 Notes and discount on the 2018 Notes		2,571			(770	)		6,318			3,077
Deferred income taxes		—			—			—			—
Non-recurring other operating items		(15,858	)		(6,314	)		(21,813	)		(6,314	)
Gain from early termination of derivative financial instruments		—			—			—			37,936
Changes in operating assets and liabilities		(7,811	)		(7,224	)		(39,422	)		(46,170	)
Settlements of derivative financial instruments with a financing element		—			—			—			907
Net cash provided by operating activities	$	127,301		$	94,143		$	355,334		$	275,996

		000000000			000000000			000000000			000000000
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Statement of cash flow data (unaudited):
Cash flow provided by (used in):
Operating activities	$	127,301		$	94,143		$	355,334		$	275,996
Investing activities		(249,217	)		(183,431	)		(446,402	)		(44,163	)
Financing activities		113,148			42,385			103,257			(249,116	)
Other financial and operating data:
EBITDA(1)		200,526			126,119			486,666			919,719
Adjusted EBITDA(1)		163,489			115,987			453,836			325,676

(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-recurring other operating items, including litigation reserves, certain asset impairments, costs associated with our special committee’s review of strategic alternatives, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, gains from early termination 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 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

13

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 $2.0 million for the nine months ended September 30, 2010 for interest rate swaps included in GAAP interest expense. Our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements as of September 30, 2011.

14

EXCO Resources, Inc.

Summary of operating data

	Three months ended							Nine months ended
	September 30,				%			September 30,				%
	2011		2010		Change			2011		2010		Change
Production:
Oil (Mbbls)		182		178		2	%		553		505		10	%
Gas (Mmcf)		48,576		28,408		71	%		128,568		76,784		67	%
Oil and natural gas (Mmcfe)		49,668		29,476		69	%		131,886		79,814		65	%
Average daily production (Mmcfe)		540		320		69	%		483		292		65	%
Average sales prices (before derivative financial instrument activities):
Oil (per Bbl)	$	85.69	$	72.85		18	%	$	91.53	$	74.13		23	%
Gas (per Mcf)		3.95		4.15		-5	%		4.08		4.47		-9	%
Total production (per Mcfe)		4.17		4.44		-6	%		4.36		4.77		-9	%
Average costs (per Mcfe):
Oil and natural gas operating costs	$	0.42	$	0.75		-44	%	$	0.46	$	0.80		-43	%
Production and ad valorem taxes		0.13		0.10		30	%		0.14		0.24		-42	%
Gathering and transportation costs		0.45		0.39		15	%		0.45		0.45		0	%
Depletion		1.93		1.69		14	%		1.82		1.57		16	%
Depreciation and amortization		0.09		0.13		-31	%		0.11		0.16		-31	%
General and administrative		0.60		0.82		-27	%		0.58		0.96		-40	%

15