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

OPERATING AND FINANCIAL

RESULTS FOR THE SECOND QUARTER 2008

DALLAS, TEXAS, August 5, 2008 …EXCO Resources, Inc. (NYSE: XCO) today announced second quarter 2008 results.

·Adjusted net income available to common shareholders, a non-GAAP measure adjusting for non-cash derivative losses and items typically not included by securities analysts in published estimates, was $0.34 per diluted share for the second quarter 2008 compared with an adjusted net loss of $0.11 per share for the second quarter 2007.

·Oil and natural gas revenues for the second quarter 2008 were $429 million, exclusive of derivative financial instrument activities (derivatives) and $338 million inclusive of cash settlements on derivatives.  Oil and natural gas revenues for the prior year’s quarter were $262 million before derivatives, and $268 million including cash settlements on derivatives.

·Oil and natural gas production for the second quarter 2008 was 36 Bcfe, or 394 Mmcfe per day comprised of 358 Mmcf per day of natural gas and 5,989 barrels of oil per day, in line with our expectations and approximately 2% higher than the first quarter 2008 production of 386 Mmcfe per day.  Presently our daily average production exceeds 400 Mmcfe per day.

·Midstream operating profit, before the effect of intercompany eliminations, was $12 million compared with $8 million in the prior year’s quarter. Operating profit after intercompany eliminations was $4 million for the three months ended June 30, 2008 and $1 million for the three months ended June 30, 2007.

·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 quarter was $263 million, approximately 26% higher that the prior year’s quarter.

·Total capital expenditures for the second quarter 2008, which include drilling and development, leasing, midstream projects and corporate expenditures, were $258 million, an increase of 115% from the prior year’s quarter. Drilling and development capital expenditures totaled $136 million for the second quarter 2008 compared with second quarter 2007 drilling and development capital expenditures of $104 million.  During the second quarter 2008, we initiated an aggressive acreage acquisition program in our shale plays in Haynesville/Bossier (Haynesville) in East Texas/North Louisiana and Marcellus in

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Appalachia.  Leasehold expenditures were approximately $78 million in these areas during the second quarter 2008.  Including the second quarter 2008 acreage acquisitions, our net acreage exceeds 119,800 net acres in the Haynesville shale and approximately 395,000 net acres in the Marcellus and Huron shale plays.

·On July 18, 2008, we converted all outstanding shares of our preferred stock into a total of approximately 105.2 million shares of our common stock.  The conversion of the preferred stock had the effect of increasing the book value of shareholders’ equity by approximately $2.0 billion. On July 21, 2008, we paid all accrued dividends plus cash in lieu of fractional shares upon conversion totaling approximately $12.8 million to the holders of the converted shares of preferred stock.  After July 18, 2008, dividends ceased to accrue on the preferred stock and all rights of the holders with respect to the preferred stock terminated. The conversion of all outstanding shares of preferred stock into common stock eliminated our obligation to pay quarterly cash dividends of $35.0 million, resulting in annual dividend savings of $140.0 million.

Douglas H. Miller, EXCO’s Chief Executive Officer commented, “The second quarter of 2008 continued the outstanding performance of EXCO in terms of revenues, cash flows and adjusted earnings.  In addition, we have made substantial progress in further defining the opportunities we have in the Haynesville, Marcellus and Huron shale plays and enhancing our acreage position.  The remainder of 2008 will see a rapid acceleration in drilling in the shales, with both vertical and horizontal tests planned.

We are continuing our development efforts in our Cotton Valley program in East Texas and North Louisiana, our shallow plays in Appalachia, and our West Texas Canyon Sand activities. However, we have reduced the number of wells to be drilled and completed in the Cotton Valley and Appalachia areas to focus more time and capital on our shale assets.

Another very positive recent event was the conversion of our preferred stock into common stock in mid-July.  This event has doubled our equity base and will enhance our free cash flow by $140 million annually.

We are optimistic about our Company’s prospects for the balance of 2008 and beyond.”

For the six months ended June 30, 2008, adjusted net income available to common shareholders was $0.45 per diluted share compared with an adjusted net loss of $0.04 per dilutive share for the six months ended June 30, 2007.  Adjusted EBITDA for the six months ended June 30, 2008 was $517 million compared with $323 million for the six months ended June 30, 2007, an increase of 60%.

Equivalent production for the six months ended June 30, 2008 was 71.0 Bcfe, an increase of 36% from the prior year’s six month period equivalent production of 52.2 Bcfe.  The increase in production is primarily attributable to the 2008 period including a full six months of volumes from our 2007 acquisitions of Vernon and Southern Gas, while the 2007 six months contain only three months of Vernon and two months of Southern Gas.

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The average price per barrel of oil, excluding derivatives, was $109.21 per Bbl for the six months ended June 30, 2008 compared with $58.72 for the prior year’s six month period.  The average natural gas price, excluding derivatives for the six months ended June 30, 2008 and 2007 was $9.87 and $7.10 per Mcf, respectively, an increase of approximately 39%.

Revenues and adjusted revenues

Our second quarter 2008 adjusted revenues, a non-GAAP measure defined as revenues which exclude the non-cash impact of our oil and natural gas derivatives, were $367 million, an increase of $92 million, or 33% from the second quarter 2007.  The increase was primarily attributable to higher product prices, before derivatives, which increased by 59% on a per Mcfe basis over the prior year’s quarter.  Realized prices, after cash settlements on derivatives, were $9.42 per Mcfe and $7.69 per Mcfe for the three months ended June 30, 2008 and 2007, respectively.

	Three months ended June 30,						%		Six months ended June 30,						%
(in thousands, except prices)	2008			2007			change		2008			2007			change
Oil and natural gas revenues, before derivative financial instruments	$	428,651		$	261,552		64	%	$	753,594		$	381,911		97	%
Cash settlements on derivative financial instruments	(90,380		)	6,630					(87,364		)	38,702
Subtotal, revenues including cash settlements on derivative financial instruments	338,271			268,182			26	%	666,230			420,613			58	%
Non-cash gain (loss) on oil and natural gas derivative financial instruments	(572,273		)	71,267					(916,483		)	(56,824		)
Oil and natural gas revenues	(234,002		)	339,449					(250,253		)	363,789
Midstream revenues	26,956			5,211			417	%	34,848			9,757			257	%
Other income	2,249			1,883			19	%	3,676			5,162			-29	%
Total revenues and other income, GAAP	(204,797		)	346,543					(211,729		)	378,708
Elimination of non-cash oil and natural gas derivative financial instruments activity included in GAAP revenues	572,273			(71,267		)			916,483			56,824
Adjusted revenues (1)	$	367,476		$	275,276		33	%	$	704,754		$	435,532		62	%
							��
Prices, excluding marketing and other income:
Realized price per Mcfe, before derivative financial instruments	$	11.94		$	7.50		59	%	$	10.62		$	7.32		45	%
Realized price per Mcfe, after cash settlements on derivative financial instruments	$	9.42		$	7.69		22	%	$	9.39		$	8.06		17	%

(1)EXCO does not designate its derivatives as hedges.  As a result, unrealized gains or losses in the fair market value of our derivatives are recognized as a component of current revenues.  Adjusted revenues are not a measure of revenues in accordance with GAAP.  Management believes that adjusted revenue is a meaningful measure to investors and rating agencies as it presents the combination of actual revenues before the impact of oil and natural gas derivatives in accordance with GAAP, combined with the actual cash receipts or settlements arising from the oil and natural gas derivative program. Adjusted revenues specifically exclude the non-cash unrealized gains or losses from derivative activities as the non-cash impact of the changes in the fair value of derivatives does not impact our current liquidity and cash flows used to fund our operations, execute our capital program and make acquisitions.

Cash Flow

Our cash flow from operations before working capital changes and adjustments for settlements of derivative financial instruments with a financing element for the current quarter was $232 million, or a 32% increase from the prior year’s second quarter. We utilized this cash flow primarily to fund our development and exploitation projects and acquire acreage in our Haynesville/Bossier and Marcellus shale plays.

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	Three months ended June 30,						%		Six months ended June 30,						%
(in thousands)	2008			2007			change		2008			2007			change
Cash flow from operations, GAAP	$	312,724		$	136,575				$	512,234		$	169,126
Net change in working capital	(8,283		)	42,358					3,773			57,697
Cash settlements of assumed derivatives financing element	(72,566		)	(3,678		)			(62,099		)	(3,678		)
Cash flow from operations before changes in working capital, non-GAAP measure (1)	$	231,875		$	175,255		32	%	$	453,908		$	223,145		103	%

(1)Cash flow from operations before working capital changes 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 provide 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 with the intended measure of our ability to provide cash to fund operations and development activities.

Net Income

Our reported net income (loss) and net income (loss) available to common shareholders shown below, both GAAP measures, include certain items not typically included by securities analysts in their published estimates of financial results. Management is disclosing the non-GAAP measures of adjusted net income (loss) and adjusted net income (loss) available to common shareholders because it quantifies the financial impact of non-cash gains or losses resulting from derivatives and certain items management believes affect the comparability of our results of operations which are included in GAAP net income measures. The following table provides a reconciliation of our net income (loss) and net income (loss) available to common shareholders to non-GAAP measures of adjusted net income (loss) and adjusted net income (loss) available to common shareholders:

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	Three months ended June 30, 2008				Three months ended June 30, 2007				Six months ended June 30, 2008				Six months ended June 30, 2007
(in thousands, except per share amounts)	Amount		Per share		Amount		Per share		Amount		Per share		Amount		Per share
Net income (loss), GAAP	$(262,914	)			$82,886				$(425,753	)			$(4,811	)
Adjustments:
Non-cash mark-to-market (gains) losses on oil and natural gas derivative financial instruments, before taxes	572,273				(71,267	)			916,483				56,824
Non-cash mark-to-market (gains) losses on interest rate derivative financial instruments, before taxes	(11,001	)			—				(7,370	)			—
Nonrecurring financing costs, before taxes (1)	—				—				—				32,100
Income taxes on adjustments (2)	(224,509	)			28,507				(363,645	)			(35,570	)
Total adjustments, net of taxes	336,763				(42,760	)			545,468				53,354
Adjusted net income	$73,849				$40,126				$119,715				$48,543
Net income (loss) available to common shareholders, GAAP (3)	$(297,914	)	$(2.83	)	$31,787		$0.30		$(495,753	)	$(4.72	)	$(57,046	)	$(0.55	)
Adjustments shown above (3)	336,763		3.20		(42,760	)	(0.41	)	545,468		5.20		53,354		0.51
Dilution attributable to stock options (4)	—		(0.02	)	—		n/a		—		(0.03	)	—		n/a
Adjusted net income (loss) available to common shareholders	$38,849		$0.35		$(10,973	)	$(0.11	)	$49,715		$0.45		$(3,692	)	$(0.04	)
Benefit of preferred dividends due to assumed conversion (5)	$35,000		—		n/a		—		n/a		—		n/a		—
Adjusted net income (loss) available to common shareholders	38,849		—		(10,973	)	—		49,715		—		(3,692	)	—
Adjusted net income (loss) for diluted earnings per share (5)	$73,849		$0.34		$(10,973	)	$(0.11	)	$49,715		$0.45		$(3,692	)	$(0.04	)
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding			105,253				104,313				104,968				104,258
Dilutive stock options			5,774				n/a				4,351				n/a
Shares used to compute EPS for adjusted net income (loss) available to common shareholders			111,027				104,313				109,319				104,258
Dilutive preferred stock			105,263				n/a				n/a				n/a
Shares used to compute diluted EPS for adjusted net income (loss) available to common shareholders			216,290				104,313				109,319				104,258

(1)See “Condensed consolidated statement of operations” for a detailed explanation.

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

(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.

(5)Preferred stock was dilutive to adjusted net income for the three months ended June 30, 2008.  Therefore, the assumed conversion of preferred stock and related dividend savings are included in the diluted earnings per share computation. Diluted income per share for the six months ended June 30, 2008 is computed using the weighted average common stock and dilutive stock options.  The assumed conversion of preferred stock is not included in the diluted per share computation as those shares are antidilutive for the six month period ended June 30, 2008.  The three and six months ended June 30, 2007 per share losses are computed using only the weighted average common stock outstanding as the stock options and assumed conversion of preferred stock are antidilutive.

Development and Exploitation Activity

We spent $136 million on development and exploitation activities, drilling and completing 130 gross (109.9 net) wells in the second quarter of 2008.  Our overall drilling success rate exceeded 99%.  Our total capital expenditures, including leasing, midstream and corporate activities, totaled $258 million.  We currently have 28 drilling rigs operating across our portfolio.

As commodity prices have increased, our direct operating costs have increased from $0.95 per Mcfe in the first quarter 2008 to $1.13 per Mcfe in the second quarter 2008.  Our fuel costs have increased approximately 40% since the start of the year and we spent $2.3 million more on workover activities in the second quarter 2008 versus first quarter 2008.

Capital costs have increased as well.  Our casing and tubular costs have increased approximately 40% - 80% since the start of the year.  Some drilling rig day rates have increased from $18,000 per day to $21,500 per day and some new 1,500 horsepower top-drive rigs have increased in cost from approximately $23,500 to $27,000 per day.  However, as many of our rigs are on older long-term

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contracts, we have not as yet been significantly impacted by the change in rig rates.

During the second quarter of 2008, our Board of Directors approved a revised 2008 capital budget totaling $943 million.  More than 60% of this revised budget will be spent to drill and complete 608 gross wells.  As we have reallocated some capital originally planned for drilling conventional, shallow Appalachian wells into shale drilling, we have reduced our forecast number of wells to be drilled.  Our plans for the remainder of 2008 include exploiting our holdings in Haynesville, Marcellus and Huron shale areas as well as development drilling in all of our operating areas.  The following table details our capital budget for 2008:

		Drilling and						Operations
	Gross wells	completion		Exploitation		Land		and other		Total
	(#)	(net $ mm)		(net $ mm)		(net $ mm)		(net $ mm)		(net $ mm) (1)
East Texas/North Louisiana:
Cotton Valley	141	$	297	$	26	$	10	$	58	$	391
Haynesville/Bossier Shale	20	32		—		54		4		90
Appalachia:
Conventional	229	54		4		1		14		73
Marcellus/Huron Shale	20	54		—		116		—		170
Mid-Continent	57	48		4		—		5		57
Permian	137	98		1		3		7		109
Rockies and other	4	11		—		1		3		15
Total	608	$	594	$	35	$	185	$	91	$	905

(1)Does not include $19 million for information technology and other and $19 million for Midstream.

The concentration during 2008 will include the specific activity noted in the following areas:

East Texas/North Louisiana

East Texas/North Louisiana is our largest division in terms of production and reserves, and our primary targets across this region have been the upper and lower Cotton Valley, Travis Peak, Pettet and Hosston formations.  While we are continuing our original plan to drill and exploit these formations, we are increasing emphasis and expanding our activity in our Haynesville shale play position, which now exceeds 119,800 net acres.  To support this increased Haynesville shale activity, we increased our 2008 capital budget for the division to $481 million, with $90 million allocated to Haynesville shale activities (primarily leasing, drilling and completion activity).

A significant amount of our Haynesville shale acreage is held by production (HBP), and is within areas of the play which have been proven productive by both our and our competitors’ drilling and completion activities.  Our current plans for 2008 include drilling 17 vertical and three horizontal Haynesville tests.   To date, we have strategically focused on adding to our leasehold and on drilling to delineate the shale play rather than focusing on maximizing production from the shales.  To date, we have drilled four vertical wells and plan to spud our first horizontal well in August.  This 2008 activity will add to our HBP position, continue to delineate the play and add to our production volumes in the future.  Our drilling to date in Harrison County, Texas and Caddo and DeSoto Parishes, Louisiana has identified Haynesville/Bossier shale thickness averaging 200 feet of net pay with high porosities and total organic carbon indicating significant gas in place.  Our initial production rates from these vertical well tests have ranged from 800 to 2,800 Mcf per day at flowing pressures ranging from 1,000 to 3,200 psi.  We are continuing to refine our fracture technologies and

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methodologies. We have plans for increased activity in the Haynesville shale in 2009, and accordingly have signed long-term commitments with drilling contractors for five 1,500 horsepower, top drive drilling rigs capable of drilling horizontal Haynesville wells.  Our first horizontal Haynesville well is scheduled to spud in August 2008, and the remaining four rigs will be delivered to us beginning in November and continuing through the second quarter 2009.

In addition to the 20 shale wells mentioned above, we plan to drill 141 conventional wells in 2008 in the East Texas/North Louisiana division.  We currently have 11 rigs operating in the region, with four of these rigs drilling in our Vernon Field in Jackson Parish, Louisiana, where we continue to expand our field limits with successful step out drilling.  We are evaluating seismic on 35,000 acres immediately north of the Vernon Field, with plans to spud a Cotton Valley test well in late 2008.  We have five rigs operating in our Shreveport area, which includes our Holly/Caspiana Field and our Longwood/Greenwood/Waskom area.  Our Holly/Caspiana Field has significant drilling activity in the traditional Cotton Valley plays and both areas have Haynesville opportunities.  In the second quarter, we drilled and completed 42 gross (31.1 net) wells in the East Texas/North Louisiana area with a 100% success rate.

Our Midstream operations in East Texas/North Louisiana continue to grow from both third party and company-owned production throughput.  Current throughput is approximately 535 Mmcf per day, with approximately 60% of the throughput from equity volumes and 40% from third parties.  We are nearing completion of our $37.6 million, 57-mile, predominantly 20-inch diameter TGG intrastate pipeline expansion.  A first phase of the expansion encompassing 20-miles of line was available for service during the second quarter, and the remaining 37 miles will be installed and operational prior to year-end.  This expansion will allow us to add an incremental 100 Mmcf per day without compression to the existing throughput volumes.  With compression, incremental throughput volumes could exceed 200 Mmcf per day.  We are evaluating opportunities to expand our Midstream operations throughout the East Texas/North Louisiana region to support continued development of the Haynesville shale.

Appalachia

In Appalachia, our major operating areas include Pennsylvania, Ohio, and West Virginia, where we typically drill for and exploit the Clinton/Medina sandstone, stacked Devonian sandstones, Devonian shales, Berea shale, and other productive horizons.  During the second quarter, we drilled and completed 45 gross (41.4 net) wells in our Appalachian division.  We had one dry hole, resulting in a quarterly success rate of 98%.  We plan to drill 229 gross wells to our conventional Appalachian targets during 2008, and we currently have nine rigs drilling in the region.

The targeted number of wells is a reduction from the 330 well target we previously announced, as we are reallocating resources to our shale efforts.  Significant focus and effort is directed to our extensive Marcellus and Huron shale holdings in Pennsylvania and West Virginia.  During the second quarter, we spud two horizontal Marcellus wells in Central Pennsylvania, three vertical Marcellus wells in West Virginia, and one horizontal Huron shale well, also in West Virginia.  By year end, we plan to drill and complete an additional two Marcellus horizontal wells, an additional

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four vertical Marcellus wells, and approximately seven additional Huron horizontal wells, two of which we have already begun drilling.  Our first Marcellus well, which we plan to complete during the third quarter 2008, found a shale thickness of 194 feet, with relatively high average porosity and total organic carbon.

We hold nearly 1.1 million net leasehold acres in the Appalachian Basin.  Included in this leasehold are approximately 395,000 acres of Marcellus potential and 121,000 acres of Huron potential.  Within the Marcellus acreage, we believe approximately 276,000 acres are in the core, overpressured area of the play, and approximately 70% of our acreage is held by shallow production.

While the Huron play can be developed with equipment already present in the basin, the Marcellus play will require additional, larger, fit-for-purpose drilling rigs to be brought into the basin.  Accordingly, we have signed long term contracts with a drilling rig contractor to provide two 1,000 horsepower, top-drive rigs which will be delivered to us beginning in early 2009.

Other

Our Permian Canyon Sand field development and extension work is continuing.  We drilled and completed 31 gross (30.1 net) wells in our Permian area (all of which were in our Canyon Sand Field) in the second quarter and achieved 100% success rate on our drilling.  We plan to drill 124 wells in the field during 2008.  Of the $109 million budgeted for the Permian Area in 2008, approximately $80 million is allocated for drilling and completion in the Canyon Sand field where we have three drilling rigs operating.  In the first quarter 2008, we finalized a joint venture including approximately 11,000 contiguous net acres adjacent to this field.  We have acquired and are evaluating 3-D seismic data over this 11,000 acre block and plan to drill at least two wells in this area by year-end 2008.  In the second quarter 2008, we leased an additional 12,300 net acres adjacent to our Canyon Sand field and plan to acquire 3-D seismic over this acreage by year-end 2008.  Our total leasehold in the Canyon Sand field now exceeds 47,000 net acres.

In our Mid-Continent division, we drilled 12 gross (7.3 net) wells during the second quarter and achieved a 100% drilling success rate.  We have budgeted to drill 57 gross wells in the region this year, and had four rigs drilling on our acreage at the end of the second quarter 2008.

We are budgeting $57 million of capital for the Mid-Continent area and $15 million for the Rockies and other plays in West Texas and other areas.

Acquisitions

On July 15, 2008, we acquired natural gas properties in East Texas (primarily in Gregg, Rusk and Upshur Counties) from private sellers for $244 million after preliminary closing adjustments.  The properties include more than 15 Mmcfe per day of net production from 83 producing wells, more than 500 Cotton Valley, Travis Peak and Rodessa drilling locations, 92 of which are proved, and approximately 109 Bcfe of proved reserves as calculated based on NYMEX strip pricing in effect at the effective date of acquisition.  The properties also include some 11,000 gross acres, a significant

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amount of which has deep rights.  We plan to spend $20 million of capital in this acquisition area in 2008 and drill nine wells by year-end, at least one of which will be drilled into the Haynesville.

Liquidity

On August 1, 2008 our combined borrowing base on our revolving credit facilities was approximately $2.5 billion, and our unused borrowing capacity was $255.6 million.

On July 15, 2008, we entered into a $500 million senior unsecured term credit agreement and utilized $300 million to fund the acquisition of the East Texas properties previously discussed.

Financial Data

Our condensed consolidated balance sheets as of June 30, 2008 (unaudited) and December 31, 2007, unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2008 and 2007, and unaudited condensed consolidated statements of cash flows for the six months ended June 30, 2008 and 2007, 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, August 6, 2008 at 1:30 p.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#564162851.  The conference call will also be webcast on EXCO’s website at http://www.excoresources.com under the Investor Relations tab.  Presentation materials related to this release will be posted on EXCO’s website on Tuesday, August 5, 2008, after market close.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., August 13, 2008.  Please call (800) 642-1687 and enter conference ID# 45480181 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 at http://www.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 for the year ended December 31, 2007 and our other periodic filings with the SEC.

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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 has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only 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.  We use the terms “probable,” “possible,” “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 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, 2007 available on our website at www.excoresources.com under the Investor Relations tab or by calling us at 214-368-2084.

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EXCO Resources, Inc.

Condensed consolidated balance sheets

	June 30,			December 31,
(in thousands)	2008			2007
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	34,142		$	55,510
Accounts receivable:
Oil and natural gas	229,567			146,297
Joint interest	19,378			21,614
Interest and other	4,811			2,151
Derivative financial instruments	2,808			66,632
Deferred income taxes	209,601			6,764
Other	27,077			12,332
Total current assets	527,384			311,300
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties	453,680			334,803
Proved developed and undeveloped oil and natural gas properties	5,667,619			4,926,053
Accumulated depletion	(709,572		)	(500,493		)
Oil and natural gas properties, net	5,411,727			4,760,363
Gas gathering assets	442,865			340,706
Accumulated depreciation and amortization	(23,794		)	(16,142		)
Gas gathering assets, net	419,071			324,564
Office and field equipment, net	23,456			20,844
Advance on pending acquisition	25,206			39,500
Derivative financial instruments	4,562			2,491
Deferred financing costs, net	18,705			20,406
Other assets	1,398			6,226
Goodwill	470,077			470,077
Total assets	$	6,901,586		$	5,955,771

11

EXCO Resources, Inc.

Condensed consolidated balance sheets

	June 30,			December 31,
(in thousands, except per share and share data)	2008			2007
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	153,570		$	106,305
Accrued interest payable	22,094			21,835
Revenues and royalties payable	149,145			100,978
Income taxes payable	80			87
Current portion of asset retirement obligations	1,861			1,656
Derivative financial instruments	598,860			47,306
Total current liabilities	925,610			278,167
Long-term debt	2,618,013			2,099,171
Asset retirement obligations and other long-term liabilities	105,699			89,810
Deferred income taxes	213,991			271,398
Derivative financial instruments	405,011			109,205
Commitments and contingencies	—			—
7.0% Cumulative Convertible Perpetual Preferred Stock, $0.001 par value, 39,008 shares outstanding at June 30, 2008 and December 31, 2007, liquidation preference of $391,218	388,574			388,574
Hybrid Preferred Stock, $0.001 par value, 160,992 shares outstanding at June 30, 2008 and December 31, 2007, liquidation preference of $1,614,616	1,603,704			1,603,704
Shareholders’ equity:
Preferred stock, $0.001 par value; authorized shares - 10,000,000; issued and outstanding shares - 200,000 presented above	—			—
Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 105,556,370 at June 30, 2008 and 104,578,941 at December 31, 2007	106			105
Additional paid-in capital	1,064,639			1,043,645
Retained earnings (deficit)	(423,761		)	71,992
Total shareholders’ equity	640,984			1,115,742
Total liabilities and shareholders’ equity	$	6,901,586		$	5,955,771

See accompanying notes.

(1)On July 18, 2008, we converted all outstanding shares of our preferred stock into a total of approximately 105.2 million shares of our common stock.  The conversion of the preferred stock had the effect of increasing the book value of shareholders’ equity by approximately $2.0 billion. On July 21, 2008, we paid all accrued but unpaid dividends plus cash in lieu of fractional shares upon conversion totaling approximately $12.8 million to the holders of the converted shares of preferred stock.  After July 18, 2008, dividends ceased to accrue on the preferred stock and all rights of the holders with respect to the preferred stock terminated. The conversion of all outstanding shares of preferred stock into common stock eliminated our obligation to pay quarterly cash dividends of $35.0 million, resulting in annual dividend savings of $140.0 million.

12

EXCO Resources, Inc.

Condensed consolidated statement of operations

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(in thousands, except per share data)	2008			2007			2008			2007
Revenues and other income:
Oil and natural gas	$	428,651		$	261,552		$	753,594		$	381,911
Midstream	26,956			5,211			34,848			9,757
Gain (loss) on derivative financial instruments	(662,653		)	77,897			(1,003,847		)	(18,122		)
Other income	2,249			1,883			3,676			5,162
Total revenues and other income	(204,797		)	346,543			(211,729		)	378,708
Costs and expenses:
Oil and natural gas production	62,058			47,046			114,539			76,973
Midstream operating expenses	22,824			4,139			30,851			7,103
Gathering and transportation	3,700			2,303			6,831			3,275
Depreciation, depletion and amortization	111,281			105,148			220,498			156,472
Accretion of discount on asset retirement obligations	1,473			1,267			2,789			2,210
General and administrative	19,657			14,990			42,284			29,165
Interest (1)	20,273			33,543			56,293			110,252
Total costs and expenses	241,266			208,436			474,085			385,450
Income (loss) before income taxes	(446,063		)	138,107			(685,814		)	(6,742		)
Income tax expense (benefit)	(183,149		)	55,221			(260,061		)	(1,931		)
Net income (loss)	(262,914		)	82,886			(425,753		)	(4,811		)
Preferred stock dividends	(35,000		)	(51,099		)	(70,000		)	(52,235		)
Net income (loss) available to common shareholders	$	(297,914	)	$	31,787		$	(495,753	)	$	(57,046	)
Net income (loss) per common share:
Net income (loss) per common share - basic	$	(2.83	)	$	0.30		$	(4.72	)	$	(0.55	)
Net income (loss) per common share - diluted	$	(2.83	)	$	0.30		$	(4.72	)	$	(0.55	)
Weighted average shares:
Basic	105,253			104,313			104,968			104,258
Diluted	105,253			106,909			104,968			104,258

See accompanying notes.

(1)Interest expense for the six months ended June 30, 2007 includes one time charges of $32.1 million incurred during the first quarter 2007. Expenses associated with the payoff of the EXCO Operating Company, LP Senior Term Credit Agreement included a $13.0 million redemption premium, a $9.2 million write-off of deferred financing costs, and a $3.0 million write-off of unamortized original issue discount. In addition, $6.9 million of commitment fees were expensed in connection with other debt arrangements that were terminated in the first quarter of 2007. Interest expense for the three and six months ended June 30, 2008 includes decreases to interest expense of $11.0 million and $7.4 million, respectively, a result of non-cash gains resulting from interest rate swaps entered into during the first quarter 2008.

13

EXCO Resources, Inc.

Consolidated statement of cash flows

(Unaudited)

	Six months ended June 30,
(in thousands)	2008			2007
Operating Activities:
Net loss	$	(425,753	)	$	(4,811	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	220,498			156,472
Stock option compensation expense	6,688			4,465
Accretion of discount on asset retirement obligations	2,789			2,210
Non-cash change in fair value of derivatives	909,111			56,824
Cash settlements of assumed derivatives	62,099			3,678
Deferred income taxes	(260,244		)	(1,931		)
Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011 and discount on long-term debt	817			9,916
Effect of changes in:
Accounts receivable	(83,688		)	(91,091		)
Other current assets	(13,829		)	(755		)
Accounts payable and other current liabilities	93,746			34,149
Net cash provided by operating activities	512,234			169,126
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(910,485		)	(2,353,707		)
Advance on pending acquisition	(25,205		)	5,000
Proceeds from disposition of property and equipment and other	1,532			376,041
Net cash used in investing activities	(934,158		)	(1,972,666		)
Financing Activities:
Borrowings under credit agreements	812,200			1,928,000
Repayments under credit agreements	(291,700		)	(2,023,532		)
Settlements of derivative financial instruments with a financing element	(62,099		)	(3,678		)
Proceeds from issuance of common stock	12,929			2,228
Proceeds from issuance of preferred stock	—			2,000,000
Payment of preferred stock dividends	(70,000		)	(43,717		)
Payments for preferred stock issuance costs	—			(7,498		)
Deferred financing costs	(774		)	(17,804		)
Net cash provided by financing activities	400,556			1,833,999
Net increase (decrease) in cash	(21,368		)	30,459
Cash at beginning of period	55,510			22,822
Cash at end of period	$	34,142		$	53,281
Supplemental Cash Flow Information:
Interest paid	$	63,651		$	108,662
Derivative financial instruments assumed in Vernon Acquisition	$	—		$	(60,015	)
Derivative financial instruments assumed in Southern Gas Acquisition	$	—		$	(42,204	)
Supplemental non-cash investing and financing activities:
Capitalized stock compensation	$	1,276		$	882
Capitalized interest	$	316		$	—
Issuance of common stock for director services	$	102		$	—
Value of shares received for sale of properties	$	—		$	3,431

See accompanying notes.

14

EXCO Resources, Inc.

Consolidated EBITDA

And adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2008			2007			2008			2007
Net income (loss)	$	(262,914	)	$	82,886		$	(425,753	)	$	(4,811	)
Interest expense	20,273			33,543			56,293			110,252
Income tax expense (benefit)	(183,149		)	55,221			(260,061		)	(1,931		)
Depreciation, depletion and amortization	111,281			105,148			220,498			156,472
EBITDA(1)	(314,509		)	276,798			(409,023		)	259,982
Accretion of discount on asset retirement obligations	1,473			1,267			2,789			2,210
Non-cash change in fair value of oil and natural gas derivative financial instruments	572,273			(71,267		)	916,483			56,824
Stock- based compensation expense	3,684			2,554			6,688			4,465
Adjusted EBITDA(1)	262,921			209,352			516,937			323,481
Interest expense (2)	(31,274		)	(33,543		)	(63,663		)	(110,252		)
Income tax benefit (expense)	183,149			(55,221		)	260,061			1,931
Amortization of deferred financing costs, premium on 7 1/4% senior notes due 2011 and discount on long-term debt	411			561			817			9,916
Deferred income taxes	(183,332		)	54,106			(260,244		)	(1,931		)
Changes in operating assets and liabilities and other	8,283			(42,358		)	(3,773		)	(57,697		)
Settlements of derivative financial instruments with a financing element	72,566			3,678			62,099			3,678
Net cash provided by operating activities	$	312,724		$	136,575		$	512,234		$	169,126

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2008			2007			2008			2007
Statement of cash flow data:
Cash flow provided by (used in):
Operating activities(2)	$	312,724		$	136,575		$	512,234		$	169,126
Investing activities	(329,289		)	(571,310		)	(934,158		)	(1,972,666		)
Financing activities	41,594			318,338			400,556			1,833,999
Other financial and operating data:
EBITDA(1)	(314,509		)	276,798			(409,023		)	259,982
Adjusted EBITDA(1)	262,921			209,352			516,937			323,481

(1)Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes, depreciation, depletion and amortization.  “Adjusted EBITDA” represents EBITDA adjusted to exclude accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives and stock-based compensation. 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 agreements and the indenture governing our 7 1/4 % senior notes. 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

15

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 change in fair value of interest rate swaps included in GAAP interest expense.

16

EXCO Resources, Inc.

Summary of operating data

	Three months ended June 30,				%		Six months ended June 30,				%
	2008		2007		Change		2008		2007		Change
Production:
Oil (Mbbls)	545		426		28	%	1,053		701		50	%
Gas (Mmcf)	32,621		32,320		1	%	64,670		47,983		35	%
Oil and natural gas (Mmcfe)	35,891		34,876		3	%	70,988		52,189		36	%
Average sales prices (before derivative financial instrument activities):
Oil (per Bbl)	$	121.07	$	61.17	98	%	$	109.21	$	58.72	86	%
Gas (per Mcf)	11.12		7.29		53	%	9.87		7.10		39	%
Total production (per Mcfe)	11.94		7.50		59	%	10.62		7.32		45	%
Average costs (per Mcfe):
Oil and natural gas operating costs	$	1.13	$	0.86	31	%	$	1.04	$	0.99	5	%
Gathering and transportation costs	0.10		0.07		43	%	0.10		0.06		67	%
Production and ad valorem taxes	0.60		0.49		22	%	0.57		0.49		16	%
General and adminstrative	0.55		0.43		28	%	0.60		0.56		7	%
Depletion	2.93		2.89		1	%	2.95		2.86		3	%
Depreciation and amortization	0.17		0.13		31	%	0.16		0.14		14	%

17