Exco Resources (EXCO) 8-K Exco Resources, Inc. Reports

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 2010 RESULTS

DALLAS, TEXAS, November 2, 2010…EXCO Resources, Inc. (NYSE: XCO) today announced its third quarter 2010 results of operations. Highlights during the quarter include:

• Adjusted net income, a non-GAAP measure adjusting for unrealized derivative gains and losses and other non-cash items typically not included by securities analysts in published estimates, was $0.16 per share for the third quarter 2010.

• Oil and natural gas production was 29.5 Bcfe, reflecting daily production of 320 Mmcfe per day, for the third quarter 2010. The third quarter 2010 production represents a 45% increase from pro forma third quarter 2009 of 20.4 Bcfe, or 222 Mmcfe per day. The increased production highlights the success of our Haynesville shale drilling program where we produced 15.9 Bcfe (173 Mmcfe per day), representing 54% of our total production during the third quarter 2010 compared with 3.7 Bcfe (40 Mmcf per day), or 18% of our total production, in the pro forma third quarter 2009. The following table presents the 2010 third quarter and year-to-date pro forma production compared with the 2009 third quarter and year-to-date pro forma production.

	Three months ended September 30,
	2010				2009				Quarter to quarter change
	Pro forma				Pro forma				Pro forma
(in Mmcfe)	production (1)		Per day		production (2)		Per day		production			Per day
Producing region:
East Texas/North Louisiana		26,045		283		16,927		184		9,118			99
Appalachia		1,608		17		1,644		18		(36	)		(1	)
Permian and other		1,823		20		1,818		20		5			—
Total		29,476		320		20,389		222		9,087			98
	Nine months ended September 30,
	2010				2009				Year-to-date change
	Pro forma				Pro forma				Pro forma
(in Mmcfe)	production (1)		Per day		production (2)		Per day		production			Per day
Producing region:
East Texas/North Louisiana		66,895		245		47,665		175		19,230			70
Appalachia		4,911		18		5,250		19		(339	)		(1	)
Permian and other		5,301		19		6,185		22		(884	)		(3	)
Total		77,107		282		59,100		216		18,007			66

(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.

• Oil and natural gas revenues for the third quarter 2010 were $131 million, exclusive of the impacts of derivative financial instruments (derivatives), compared with the third quarter 2009 oil and natural gas revenues of $125 million. Revenues attributable to production from sold properties were almost entirely offset by revenues from production attributable to our development drilling. Revenues were also impacted to a smaller degree by higher realized prices for oil and natural gas, which increased by 13% on a per Mcfe basis from the prior year’s third quarter. When the impacts of cash settlements from our oil and natural gas derivatives are considered, the oil and natural gas revenues, as adjusted, were $174 million for the third quarter 2010 compared with $239 million for the third quarter 2009.

• Adjusted EBITDA, defined as earnings before interest, taxes, depreciation, depletion and amortization and other non-cash income and expense items (a non-GAAP measure) for the third quarter 2010 was $116 million compared with $173 million in the third quarter 2009. The lower Adjusted EBITDA primarily reflects lower cash settlements from our oil and natural gas derivatives, which were partially offset by higher realized prices for oil and natural gas.

• Our jointly-owned midstream entity with BG Group in East Texas and North Louisiana, TGGT, had average throughput of 1.2 Bcf per day during the third quarter 2010, an increase of 20% from the second quarter 2010. TGGT expects increased throughput due to continued development from our DeSoto Parish drilling program and a major expansion to gather and treat volumes from our recently acquired assets in the Shelby Trough in East Texas.

• On September 15, 2010, we completed an underwritten offering of $750 million of Senior Notes due September 15, 2018, resulting in net proceeds of $724 million after deducting an original issue discount of $11 million and commissions, estimated offering fees and expenses of $15 million. We used a portion of the proceeds to retire all of our Senior Notes due in January 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 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.

Douglas H. Miller, EXCO’s Chairman and CEO, commented: “The third quarter 2010 results reflect the continued strength of our Haynesville development. Although we sold 36% of our 2009 third quarter production, we have almost fully replaced those volumes through the drill bit. During the quarter, we began developing our core DeSoto Parish position on 80-acre spacing utilizing multi-well pads. We also began our development activities in the Shelby Trough where we have participated in a well which IP’d at over 35 Mmcf per day. In Appalachia, we will complete two multi-well pads in the fourth quarter. As we plan for 2011, we are focused on reducing costs, particularly drilling and completion costs. We will finalize our 2011 capital budget in November and will announce those plans at that time.”

2

Net Income

Our reported net income (loss), a GAAP measure, includes certain items not typically included by securities analysts in their published estimates of financial results. Management is disclosing the non-GAAP measure of adjusted net income because it quantifies the financial impact of non-cash gains or losses resulting from derivatives, non-cash ceiling test write-downs and other items management believes affect the comparability of our results of operations which are included in the GAAP net income measure. The following table provides a reconciliation of our net income (loss) to the non-GAAP measure of adjusted net income.

	Three months ended						Three months ended						Nine months ended						Nine months ended
	September 30, 2010						September 30, 2009						September 30, 2010						September 30, 2009
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	64,896					$	433,330					$	744,777					$	(738,273	)
Adjustments:
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes		(13,134	)					98,800						8,577						144,996
Gain on divestitures and non-recurring other operating items		6,442						(460,626	)					(568,436	)					(460,626	)
Non-cash write down of oil and natural gas properties		—						—						—						1,293,579
Income taxes on above adjustments (1)		2,677						144,730						223,944						(391,180	)
Adjustment to deferred tax asset valuation allowance (2)		(26,501	)					(174,230	)					(295,782	)					295,677
Total adjustments, net of taxes		(30,516	)					(391,326	)					(631,697	)					882,446
Adjusted net income	$	34,380					$	42,004					$	113,080					$	144,173
Net income (loss), GAAP (3)	$	64,896		$	0.31		$	433,330		$	2.05		$	744,777		$	3.51		$	(738,273	)	$	(3.50	)
Adjustments shown above (3)		(30,516	)		(0.14	)		(391,326	)		(1.85	)		(631,697	)		(2.97	)		882,446			4.18
Dilution attributable to stock options (4)					(0.01	)											(0.02	)					—
Adjusted net income for diluted earnings per share	$	34,380		$	0.16		$	42,004		$	0.20		$	113,080		$	0.52		$	144,173		$	0.68
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding		212,480						211,266						212,356						211,118
Dilutive stock options		2,442						1,969						3,271						638
Shares used to compute diluted EPS for adjusted net income		214,922						213,235						215,627						211,756

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

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

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

(4) Represents dilution per share attributable to common stock equivalents from in-the-money stock options for periods with adjusted net income available to common shareholders.

Cash Flow

Third quarter 2010 cash flow from operations before changes in working capital, non-recurring other operating items and settlements of derivative financial instruments with a financing element (adjusted cash flow) was $108 million, a decrease from the prior year’s third quarter of $146 million due primarily to lower production volumes arising from our 2009 divestitures and joint venture transactions. The following table reconciles cash flow from operations pursuant to GAAP to the aforementioned non-GAAP measure.

3

	Three months ended								Nine months ended
	September 30,					%			September 30,						%
(in thousands)	2010		2009			Change			2010			2009			Change
Cash flow from operations, GAAP	$	94,143	$	122,924					$	275,996		$	349,857
Net change in working capital		7,224		(28,884	)					46,170			(4,519	)
Non-recurring other operating items		6,314								6,314
Settlements of derivative financial instruments with a financing element		—		51,488						(907	)		141,782
Cash flow from operations before changes in working capital and non-recurring other operating items, non-GAAP measure (1)	$	107,681	$	145,528			-26	%	$	327,573		$	487,120			-33	%

(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 is 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.

Operations activity and outlook

We spent $89 million on development and exploitation activities, drilling and completing 48 gross (24.4 net) wells in the third quarter 2010, compared with 50 gross (23.8 net) wells during the second quarter 2010. We had an overall drilling success rate of 100% for the third quarter 2010. We are continuing efforts to opportunistically acquire additional leasehold in our core shale areas. Our total capital expenditures, including leasing, net of acreage reimbursements from BG Group were $146 million in the third quarter 2010. We also made equity contributions into TGGT Holdings, LLC, or TGGT, of $31.5 million.

Our projected capital spending for 2010 is presented on the following table:

	1Q		2Q		3Q		October - December
	2010		2010		2010		2010 capital		Total 2010
(in thousands)	actuals		actuals		actuals		budget		capital budget
Capital expenditures:
Development capital expenditures	$	64,993	$	102,602	$	88,567	$	83,801	$	339,963
Lease purchases (1)		8,742		12,275		8,132		7,584		36,733
Seismic		4,150		5,571		4,855		10,037		24,613
Gas gathering and water pipelines		2,128		3,895		12,745		8,150		26,918
Corporate and other		9,957		10,936		31,997		15,660		68,550
Capital expenditures before acquisitions	$	89,970	$	135,279	$	146,296	$	125,232	$	496,777

(1) Net of acreage reimbursements from BG Group totaling $66 million.

In addition to our capital program, we have closed on $509 million of acquisitions. For the nine months ended September 30, 2010, we have contributed $100 million to our midstream entities and expect to contribute $44 million during the fourth quarter 2010. TGGT is also evaluating a credit facility to fund its capital requirements. We have received $106 million through September 30, 2010 and expect to receive $26 million in the fourth quarter 2010 from BG Group for their participation in certain of our acquisitions.

4

Haynesville shale

We spud 28 operated wells during the quarter with an average fleet of 18 drilling rigs and completed 23 operated wells in the quarter. Our development success in DeSoto Parish continues and our Shelby area delivered encouraging results in the quarter with one well in our core acreage position having an IP in excess of 20 Mmcf/d in eastern Nacogdoches County, TX. We also participated in a noteworthy non-operated Haynesville horizontal well located in a deeper area of the Haynesville shale play in Nacogdoches County, TX. The well realized an IP rate in excess of 35 Mmcf/d and continues to perform well. We are currently running 21 operated horizontal drilling rigs in the play and plan to exit 2010 with 22 operated horizontal drilling rigs. We plan to spud approximately 126 operated horizontal wells in 2010. Since late 2008, we have spud over 140 operated horizontal wells and produced over 155 Bcf of gross natural gas to sales. Our overall average well in the DeSoto core area yields an initial production (IP) rate of approximately 22 Mmcf per day. We are testing and evaluating adjustments to our restricted choke program to determine the optimal production profile.

During the third quarter 2010, our drilling time in North Louisiana averaged 43 days from spud to rig release, and our best spud to rig release time in the quarter was 28 days. This average includes drilling of both directional and non-directional intermediate hole sections. Our drilling time improvements have been achieved by focusing on bit selection and downhole motor design.

In addition to our success in reducing well costs, we are also focused on optimizing our completions. Our primary focus on the completion optimization is the frac design, number of frac stages and materials selection. We have completed approximately 21 operated wells in our program (out of a total of 91 completions) with various design changes including a different base fluid, tighter perforation cluster spacing, higher stage count, higher proppant volumes, testing of Ottawa and resin coated sands and lower treating rates. We are monitoring production performance on these wells and are encouraged by our initial analysis. We plan to implement more cost effective design changes in our program going forward. We are utilizing three dedicated fracture stimulation fleets and continue to see greater consistency and efficiencies in our fracturing operations. These commitments have provided the necessary level of frac equipment available to us, and we have maintained a proper alignment with our drilling pace to keep a very low inventory of wells waiting on completion. We currently have only 12 wells in our completion inventory which is low considering our drilling activity level. We target a minimum working inventory of completions and always design to flow gas directly to the sales line once the well is completed. We have no wells currently waiting on pipeline. This is possible due to close coordination with our jointly-held company, TGGT, which installs the gathering lines in concert with our drilling operations in most of our development areas.

We made progress on two key water projects during the quarter that are focused on our commitment to reduce the impact of our operations on local water supplies. We are participating in a salt water disposal project that gathers produced saltwater across our acreage and delivers to a common point which reduces truck traffic and allows for disposal of produced saltwater much more efficiently and cost effectively. We are also making a significant investment in a water supply project which uses discharge water from a local paper plant as a key water source for our fracture stimulation operations. This solution provides relief on local water supply, reduces truck traffic and provides an environmentally friendly option for water procurement. This project is proceeding as planned, and we have just commissioned the first four miles of the planned twelve miles of 24-inch supply line. We are currently using this first segment of supply line and this new water source in our fracturing operations. We expect to have all twelve miles fully operational by the end of the year.

5

Marcellus shale

During 2010, our Marcellus development program has been focused in Central Pennsylvania where we have a contiguous land position within close proximity to pipeline infrastructure so we can promptly transport our production to market. We are currently running two operated horizontal drilling rigs in the play. During the third quarter 2010, we drilled six horizontal wells from two common pads (three wells per pad). The lengths of the laterals in these wells range from approximately 4,200 feet to more than 5,700 feet. We completed three of the wells in October 2010 and are monitoring and testing flowback techniques. We are also currently completing the next three wells and are varying our completion designs to determine optimum frac rate and size, cluster length and spacing, overall stage length, and flowback procedures, among others. For the full year 2010, we plan to drill and complete 10 gross operated horizontal wells in the play and to exit 2010 with three operated horizontal drilling rigs.

We are integrating our joint venture team and processes, following closing of the joint venture with BG Group late in the second quarter of 2010. We have a strong commitment to technical excellence, and continue to add to our technical staff. We are members of major geologic and reservoir engineering Marcellus shale consortiums, participate in several study projects, and are active in Marcellus–focused industry associations and coalitions. We have conducted 3-D seismic surveys targeting the Marcellus shale opportunity on over 53 square miles to date, with several additional 3-D surveys planned during 2010 and 2011 and continue to utilize 2-D seismic for reconnaissance. We continue to evaluate opportunities to acquire additional acreage to enhance our position within the play.

Permian

We drilled and completed 15 gross (14.6 net) wells in our Permian area Canyon Sand field during the third quarter 2010. Our overall drilling success rate in the Permian area for the third quarter 2010 was 100%. We continue to use two operated rigs in the Canyon Sand field and plan to drill and complete 56 gross (54.4 net) wells in 2010.

Midstream

Through our jointly-held midstream company, TGGT, we have begun major midstream expansion efforts in our newly acquired assets in the Shelby Trough area in East Texas. We are currently installing the infrastructure and pipeline systems necessary to treat and gather the significant production volumes expected from this area. Our current treating capacity in our North Louisiana area is 0.9 Bcf per day and we anticipate having a total capacity of approximately 1.1 Bcf per day of treating capacity by early fourth quarter 2010. TGGT had revenue throughput of approximately 1.2 Bcf per day during the third quarter 2010, which was a 20% increase over the second quarter 2010. We continue to see growth in throughput in both our legacy East Texas area as well as in our North Louisiana area, and TGGT is experiencing sustained financial growth.

6

Financial Data

Our consolidated balance sheets as of September 30, 2010 and December 31, 2009, consolidated statements of operations for the three and nine months ended September 30, 2010 and 2009 and consolidated statements of cash flows for the nine months ended September 30, 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 Wednesday, November 3, 2010 at 8:00 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# 16270280. 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 2, 2010, 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 18, 2010. Please call (800) 642-1687 and enter conference call ID# 16270280 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 for the year ended December 31, 2009 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 for the year ended December 31, 2009, which is available on our website at www.excoresources.com under the Investor Relations tab.

8

EXCO Resources, Inc.

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

9

EXCO Resources, Inc.

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		—			210
Derivative financial instruments		—			3,264
Total current liabilities		254,811			212,914
Long-term debt, net of current maturities		993,417			1,196,277
Deferred income taxes		—			—
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		—			—
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	)		—
Total shareholders’ equity		1,599,871			859,588
Total liabilities and shareholders’ equity	$	2,912,015		$	2,358,894

10

EXCO Resources, Inc.

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		—			—			—			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

11

EXCO Resources, Inc.

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		—			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		—			(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		—			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	)		—
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			—
Repayment of 2011 Notes		(444,720	)		—
Proceeds from issuance of common stock		9,776			5,400
Payment of common stock dividends		(21,238	)		—
Payment for common shares repurchased		(7,479	)		—
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		$	—
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

12

EXCO Resources, Inc.

Consolidated EBITDA

And adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2010			2009			2010			2009
Net income (loss)	$	64,896		$	433,330		$	744,777		$	(738,273	)
Interest expense		8,440			46,737			33,550			129,760
Income tax expense		(904	)		(1,921	)		3,548			189
Depreciation, depletion and amortization		53,687			50,709			137,844			187,683
EBITDA(1)		126,119			528,855			919,719			(420,641	)
Accretion of discount on asset retirement obligations		830			1,767			2,920			5,856
Non-cash write-down of oil and natural gas properties		—			—			—			1,293,579
Gain on divestitures and non-recurring other operating items		6,442			(460,626	)		(568,436	)		(460,626	)
Equity method income		(6,675	)		426			(12,054	)		426
Non-cash change in fair value of derivative financial instruments		(13,134	)		99,045			10,595			149,246
Stock based compensation expense		2,405			3,383			10,868			9,863
Adjusted EBITDA (1)	$	115,987		$	172,850		$	363,612		$	577,703
Interest expense (2)		(8,440	)		(46,982	)		(35,568	)		(134,010	)
Income tax expense		904			1,921			(3,548	)		(189	)
Amortization of deferred financing costs, premium on the 2011 Notes and discount on the 2018 Notes		(770	)		20,560			3,077			44,327
Deferred income taxes		—			(2,821	)		—			(711	)
Non-crecurring other operating items		(6,314	)		—			(6,314	)		—
Changes in operating assets and liabilities		(7,224	)		28,884			(46,170	)		4,519
Settlements of derivative financial instruments with a financing element		—			(51,488	)		907			(141,782	)
Net cash provided by operating activities	$	94,143		$	122,924		$	275,996		$	349,857
	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2010			2009			2010			2009
Statement of cash flow data (unaudited):
Cash flow provided by (used in):
Operating activities	$	94,143		$	122,924		$	275,996		$	349,857
Investing activities		(183,431	)		1,104,159			(44,163	)		849,762
Financing activities		42,385			(1,302,760	)		(249,116	)		(1,201,077	)
Other financial and operating data:
EBITDA(1)		126,119			528,855			919,719			(420,641	)
Adjusted EBITDA(1)		115,987			172,850			363,612			577,703

(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 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.

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(2) Excludes non-cash changes in fair value of $0 and $0.2 million for the three months ended September 30, 2010 and 2009, respectively, and $2.0 million and $4.3 million for the nine months ended September 30, 2010 and 2009, respectively, for interest rate swaps included in GAAP interest expense.

14

EXCO Resources, Inc.

Summary of operating data

	Three months ended September 30,				%			Nine months ended September 30,				%
	2010		2009		Change			2010		2009		Change
Production:
Oil (Mbbls)		178		355		-50	%		505		1,367		-63	%
Gas (Mmcf)		28,408		29,806		-5	%		76,784		96,598		-21	%
Oil and natural gas (Mmcfe)		29,476		31,936		-8	%		79,814		104,800		-24	%
Average sales prices (before derivative financial instrument activities):
Oil (per Bbl)	$	72.85	$	63.88		14	%	$	74.13	$	50.89		46	%
Gas (per Mcf)		4.15		3.45		20	%		4.47		3.88		15	%
Total production (per Mcfe)		4.44		3.93		13	%		4.77		4.24		13	%
Average costs (per Mcfe):
Oil and natural gas operating costs	$	0.75	$	1.01		-26	%	$	0.80	$	1.07		-25	%
Production and ad valorem taxes		0.10		0.33		-70	%		0.24		0.31		-23	%
Gathering and transportation costs		0.39		0.15		160	%		0.45		0.12		275	%
Depletion		1.69		1.40		21	%		1.57		1.60		-2	%
Depreciation and amortization		0.13		0.19		-32	%		0.16		0.19		-16	%
General and administrative		0.82		0.68		21	%		0.96		0.62		55	%

15

EXCO Resources, Inc.

Pro forma production data

	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.

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