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

SECOND QUARTER 2010 RESULTS

DALLAS, TEXAS, August 3, 2010…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced its second quarter 2010 results of operations. Highlights during the quarter include:

• Net income for the second quarter 2010 was $564 million, or $2.62 per diluted share, which includes gains from divestitures. Adjusted net income, a non-GAAP measure adjusting for gains on divestitures, unrealized derivative gains and losses and other non-cash items typically not included by securities analysts in published estimates, was $0.11 per share for the second quarter 2010.

• Oil and natural gas production was 26.5 Bcfe, reflecting daily production of 292 Mmcfe per day, for the second quarter 2010. Pro forma production for the second quarter 2010 was 25.5 Bcfe (280 Mmcfe per day) compared with 19.2 Bcfe (211 Mmcfe per day) pro forma second quarter 2009 production, reflecting an increase of 6.3 Bcfe, or 33%, from the prior year’s quarter which highlights the success of our Haynesville shale drilling program. Net production from our Haynesville shale operations was 11.6 Bcf (128 Mmcf per day), representing 46% of our total pro forma production during the second quarter 2010 compared with 1.9 Bcf (21 Mmcf per day), or 10% of our total production, in the pro forma second quarter 2009. Current net Haynesville volumes are in excess of 160 Mmcf per day. The following table presents the current quarter’s production and the prior year’s second quarter production on an actual and pro forma basis.

	Three months ended June 30,
	2010				2009				Quarter to quarter change
(in Mmcfe)	Actual production	Pro forma adjustment (1)		Pro forma production	Actual production	Pro forma adjustment (1)		Pro forma production	Versus actual production		Versus pro forma production
Producing region:
East Texas/North Louisiana	22,097	—		22,097	23,341	(7,973	)	15,368	(1,244	)	6,729
Appalachia	2,669	(1,085	)	1,584	5,025	(3,244	)	1,781	(2,356	)	(197	)
Permian and other	1,781	—		1,781	2,402	(388	)	2,014	(621	)	(233	)
Mid-Continent	—	—		—	5,750	(5,750	)	—	(5,750	)	—
Total	26,547	(1,085	)	25,462	36,518	(17,355	)	19,163	(9,971	)	6,299

(1) The pro forma adjustments reduce production volumes attributable to properties sold in 2009 and properties affected by the joint ventures with BG Group as if these sales had occurred on January 1, 2009.

• Oil and natural gas revenues for the second quarter 2010 were $118 million, exclusive of the impacts of derivative financial instruments (derivatives), compared with the second quarter 2009 oil and natural gas revenues of $146 million. The lower revenues reflect the impacts from our 2009 divestitures and joint venture transactions, and were partially offset by higher realized prices for oil and natural gas, which increased by 12% from the prior year’s second 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 $165 million for the second quarter 2010 compared with $288 million for the second 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 second quarter 2010 was $99 million compared with $210 million in the second quarter 2009. The lower Adjusted EBITDA reflects the impacts from our 2009 divestitures and joint venture transactions, lower cash settlements from our oil and natural gas derivatives, and were partially offset by higher realized prices for oil and natural gas, which increased by 12% from the prior year’s second quarter.

• On June 1, 2010, we closed our previously announced joint venture transaction with BG Group (“Appalachia JV”). Pursuant to the joint venture agreements, we sold 50% of substantially all of our Appalachian properties and undeveloped Marcellus shale acreage and received $835 million of proceeds, subject to final closing adjustments, plus a $150 million carry on future deep drilling costs. We recognized a $575 million pre-tax gain as a result of this sale. We will jointly operate the Appalachia assets with BG Group. Partnering with BG Group will allow us to accelerate our development activities in the Marcellus shale similar to what we have accomplished in the Haynesville shale.

• We closed two significant acreage acquisitions during the second quarter 2010. These acquisitions, which were made jointly with BG Group, added approximately 12 Mmcf per day of existing net production as well as approximately 23,800 net acres in the Shelby Trough area of the Haynesville and Bossier shale plays in East Texas. Initial production, (or IP, the highest 24-hour average rate) rates in this area have been comparable to those being achieved by EXCO in DeSoto Parish, Louisiana. The Shelby Trough represents our second major focus area in the Haynesville and Bossier shale plays.

Douglas H. Miller, EXCO’s Chairman and CEO, commented:

“During the second quarter, we continued to accomplish our growth objectives at EXCO. We began 2010 with a pro forma production rate of 214 Mmcfe per day and exited the second quarter at over 300 Mmcfe per day. Our growth target is to average a 30% annual increase in production for the next five years with corresponding increases in reserves and cash flows. Our drilling program will be funded with internally generated cash flow as a result of our joint ventures with BG Group. Our success in the Haynesville play continues to be outstanding and we are progressing in the Marcellus. In the Haynesville, we completed two successful 80 acre spacing tests of our acreage, with one two well pad and a second pad with four wells which we simultaneously fracture stimulated. As a result of these tests, we are implementing a pad development program in DeSoto Parish on 12 units. In Appalachia, we are planning to complete three wells on a single pad in the third quarter.

“We are very pleased with our acreage and development positions in our shale plays and can accomplish our goals without any planned acquisitions, although we will continue to evaluate additional acreage purchases in the core areas of these shale plays. Additionally, as a result of current market conditions, our Board of Directors has established a stock repurchase plan that gives us the flexibility to respond to opportunities to repurchase shares as we deem appropriate.”

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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 June 30, 2010						Three months ended June 30, 2009						Six months ended June 30, 2010						Six months ended June 30, 2009
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	564,313					$	(71,992	)				$	679,881					$	(1,171,603	)
Adjustments:
Non-cash mark-to-market losses on derivative financial instruments, before taxes		45,831						174,937						21,711						46,196
Gain on divestitures		(574,878	)					—						(574,878	)					—
Non-cash write down of oil and natural gas properties		—						—						—						1,293,579
Income taxes on above adjustments (1)		211,619						(69,975	)					221,267						(535,910	)
Adjustment to deferred tax asset valuation allowance (2)		(223,054	)					29,430						(269,281	)					469,907
Total adjustments, net of taxes		(540,482	)					134,392						(601,181	)					1,273,772
Adjusted net income	$	23,831					$	62,400					$	78,700					$	102,169
Net income (loss), GAAP (3)	$	564,313		$	2.66		$	(71,992	)	$	(0.34	)	$	679,881		$	3.20		$	(1,171,603	)	$	(5.55	)
Adjustments shown above (3)		(540,482	)		(2.54	)		134,392			0.64			(601,181	)		(2.83	)		1,273,772			6.03
Dilution attributable to stock options (4)					(0.01	)					(0.01	)					—						—
Adjusted net income for diluted earnings per share	$	23,831		$	0.11		$	62,400		$	0.29		$	78,700		$	0.37		$	102,169		$	0.48
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding		212,497						211,089						212,293						211,042
Dilutive stock options		3,001						920						3,227						—
Shares used to compute diluted EPS for adjusted net income		215,498						212,009						215,520						211,042

(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

Second quarter 2010 cash flow from operations before changes in working capital and settlements of derivative financial instruments with a financing element (adjusted cash flow) was $84.1 million, a decrease from the prior year’s second quarter 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 cash flow without working capital adjustments and derivative settlements with a financing element.

	Three months ended June 30,					Six months ended June 30,
(in thousands)	2010			2009		2010			2009
Cash flow from operations, GAAP	$	90,550		$	121,607	$	181,853		$	226,933
Net change in working capital		(6,443	)		2,179		38,946			24,365
Settlements of derivative financial instruments with a financing element		—			52,678		(907	)		90,294
Cash flow from operations before changes in working capital, non-GAAP measure (1)	$	84,107		$	176,464	$	219,892		$	341,592

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(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 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.

Operations activity and outlook

We spent $103 million on development and exploitation activities, drilling and completing 50 gross (23.8 net) wells in the second quarter 2010, compared with 42 gross (18.8 net) wells during the first quarter 2010. We had an overall drilling success rate of 98% for the second quarter 2010, as we completed 49 of the 50 wells drilled. We are successfully continuing efforts to opportunistically acquire additional leasehold in our core shale areas, where we added approximately 23,800 net acres in the Shelby Trough during the quarter. Our total capital expenditures, including leasing, net of acreage reimbursements from BG Group, midstream and corporate activities, were $135 million in the second quarter 2010. We also made equity contributions into TGGT Holdings, LLC, or TGGT, of $24 million.

In light of current natural gas prices, our recently announced acquisitions in the Shelby Trough and our Appalachia JV, we continue to monitor our capital activity and spending plans. Our activities will be focused in areas that meet our rate of return objectives or are subject to lease expirations. We have deferred drilling in the Haynesville shale in Harrison County, Texas and northern Caddo Parish, Louisiana because the IP rates and returns in these areas have been lower than in southern Caddo and DeSoto Parishes, Louisiana. Most of our acreage in these areas is held-by-production. In this environment, we will continue searching for opportunities to expand our acreage positions in the core areas of our shale plays. We currently have 28 drilling rigs operating across our portfolio, of which 20 are operated. Our projected capital spending for 2010 is presented on the following table:

(in thousands)	1Q 2010 actuals		2Q 2010 actuals		July - December 2010 capital budget		Total 2010 capital budget
Capital expenditures:
Development capital expenditures	$	64,993	$	102,602	$	158,950	$	326,545
Lease purchases (1)		8,742		12,275		41,241		62,258
Seismic (2)		4,150		5,571		10,165		19,886
Gas gathering and water pipelines		2,128		3,895		16,751		22,774
Corporate and other		9,957		10,936		19,400		40,293
Capital expenditures before acquisitions	$	89,970	$	135,279	$	246,507	$	471,756

(1) Net of acreage reimbursements from BG Group totaling $57 million.

(2) Net of seismic reimbursements from BG Group totaling $4 million.

In addition to our capital program, we have closed on $452 million of acquisitions. During 2010, we also plan to contribute up to $75 million to TGGT and expect to receive $131 million from BG Group for their participation in certain of our acquisitions.

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East Texas/North Louisiana

The East Texas/North Louisiana area is comprised of the Haynesville and Bossier shale plays and the Cotton Valley sand trend, which covers portions of the East Texas Basin and the Northern Louisiana Salt Basin. This area is currently our most active development area, providing more than 80% of our total production and holding significant reserve growth potential, particularly from the shales. EXCO operates over 1,200 total wells in the area, holds interests in approximately 182,000 net acres and has a significant operations base and pipeline infrastructure.

Our development drilling focus in this region is in the Haynesville shale, where a significant portion of our acreage is located in a prolific area of the play. The Haynesville shale play is 12,000-14,000 feet deep and is being developed with horizontal wells that have 4,000 – 5,000 foot laterals resulting in 16,000 – 19,000 feet of total measured depth.

We continue to produce tight gas sand reservoirs in the Cotton Valley sand trend at depths of 6,500 to 15,000 feet. Operations in the area are generally characterized by long-life reserves and high drilling success rates. Our development programs, which are currently deferred due to the commodity price environment, have been focused on infill drilling and extension of field limits.

Haynesville shale

The Haynesville shale gas play is one of the most active natural gas plays in the United States. Our current Haynesville shale activity is located in DeSoto and Caddo Parishes in Louisiana and in Harrison, Panola, Shelby, San Augustine and Nacogdoches Counties in Texas. Our joint venture with BG Group holds interests in approximately 160,000 net acres (80,000 net to EXCO) in the Haynesville shale. Approximately half of our core area acreage is held by our existing Haynesville, Cotton Valley, Hosston and Travis Peak production. In the first half of 2010, we added approximately 26,000 net acres to our Haynesville position, including approximately 23,800 net acres in the Shelby Trough in East Texas. The Shelby Trough is a second major focus area for us outside of our core DeSoto Parish position.

Our program in the Haynesville shale play has transitioned from an appraisal and testing program in late 2008 and early 2009 to a full scale horizontal development drilling program. In early 2009, we ran three operated horizontal drilling rigs in the play, and we exited 2009 with twelve operated horizontal drilling rigs. We are currently running 18 operated horizontal drilling rigs in the play and expect to exit 2010 with 22 operated horizontal drilling rigs. We plan to drill approximately 140 operated horizontal wells in 2010. Since late 2008, we have spud over 100 operated horizontal wells and produced over 100 Bcf of gross natural gas to sales. Our average IP rate for the DeSoto area is approximately 23 Mmcf per day. Our gross operated daily gas production rate currently exceeds 500 Mmcf per day.

We continue to improve our program execution and our operational focus has yielded significant improvements in drilling and completion efficiencies. The amount of time required to drill these horizontal wells has decreased from over 70 days to approximately 40 days from spud to rig release. We are also utilizing dedicated fracture stimulation fleets resulting in greater consistency and efficiencies in our fracturing operations.

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We have a strong commitment to technical evaluations to improve the understanding of our shale plays and have made appropriate investments to reduce risks. We are members of a major shale consortium, reservoir engineering consortium and several other engineering and geoscience study projects. We have acquired 2-D seismic data over a large regional area, participated in a significant 3-D seismic survey, completed installation of a broad microseismic fracture stimulation monitoring project and have additional 2-D and 3-D seismic projects in progress. In the DeSoto Parish area, we recently drilled four wells on 80-acre spacing from one drill site and then simultaneously fracture stimulated all four wells. In the same section, we drilled and equipped two vertical wells specifically for monitoring downhole microseismic activity during the fracturing operations and equipped those same two wells for long term reservoir pressure monitoring. We believe we are on the forefront among E&P companies to make these commitments for technical evaluation and long term pressure monitoring in this play.

We remain committed to reducing our impact on local water supplies and have made two major water pipeline projects a top priority. We are participating in a salt water disposal project that will gather produced saltwater across our acreage and deliver to a common point which will reduce truck traffic and dispose of produced saltwater much more efficiently and cost effectively. We are also making a significant investment in a water supply project where we will use discharge water from a local paper plant as a key water source for our fracture stimulation operations. This solution will provide relief on local water supplies, reduce truck traffic and provide an environmentally friendly option for water procurement.

Bossier shale

The Bossier shale section overlies the Haynesville shale and is as much as 1,400 feet thick. In 2009, we initiated a Bossier shale testing program with a procedure identical to one we used to evaluate the Haynesville shale. The Bossier shale is up to five times the thickness of the Haynesville shale in the DeSoto Parish area and holds significant reserve potential. We have completed two horizontal Bossier shale wells in DeSoto Parish with IP rates of 11 Mmcf per day and 13 Mmcf per day, respectively. We plan to drill and test additional Bossier horizontal test wells across our acreage in East Texas, including the Shelby Trough, and Northwest Louisiana over the next several months

Vernon/Kelleys area

The Vernon Field, located in Jackson Parish, Louisiana, accounts for approximately 28% of our current production. The field produces from the Lower Cotton Valley and Bossier Sand formations at depths ranging from 12,000 to 15,000 feet. The technical expertise obtained in the development of the Vernon Field and the exploitation of these high-pressure, high-temperature reservoirs greatly assisted in the rapid development of the Haynesville shale. While we have identified more than 100 additional well locations for infill drilling and extending the field limits, this drilling has been deferred due to the current commodity price environment. The current focus in the Vernon Field is maintaining production and minimizing our operating expense. Within the past year, we have successfully reduced our production decline rate.

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East Texas/North Louisiana Cotton Valley area

Within our Cotton Valley area, we have acreage and production in Caddo and DeSoto Parishes, Louisiana and Harrison, Panola, Gregg and Rusk Counties in Texas. We are focused on producing primarily Cotton Valley sands at depths ranging from 10,400 to 11,000 feet and the Travis Peak and Hosston Sands at 7,800 to 10,000 feet. Our economic hurdles require higher product pricing to justify development drilling at this time. Our focus in 2010 is on production enhancement through recompletions and minimizing decline rates. We recompleted eight Cotton Valley wells during the first half of 2010 to add Hosston pay intervals and plan to perform up to 28 of these recompletions in the DeSoto Parish area during 2010.

Appalachia

The Appalachian Basin includes portions of the states of Kentucky, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee and covers an area of over 185,000 square miles. The Appalachian Basin is strategically located near the high energy demand markets of the northeast United States and, as a result, the natural gas produced from the area has typically commanded a higher wellhead price relative to other North American gas areas.

Most production in the Appalachian Basin has been traditionally derived from relatively shallow, low porosity and low permeability sand and shale formations at approximate depths from 1,000 to 8,000 feet. Assets in the area are typically characterized by long reserve lives, high drilling success rates, and a large number of low productivity wells with shallow decline rates. Our operations in the area have primarily included maintaining our existing production from shallow wells and testing our Marcellus shale acreage.

The emergence of the Marcellus shale opportunity over the last several years resulted in a shift in our focus from the traditional shallow formations to the exploration and development of the Marcellus shale. We currently hold over 300,000 net acres in the Appalachian Basin, of which approximately 106,000 net acres are located in the core area of the Marcellus play. We define the core area of the Marcellus play to be geologically overpressured. We plan to concentrate our efforts in this core area, which is located in Pennsylvania and West Virginia.

Marcellus shale

The Marcellus shale play is found at approximate depths ranging from 6,000 to over 8,000 feet and typically has been exploited using horizontal drilling techniques. The Marcellus shale play extends over 400 miles in length within the Appalachian Basin. More than 70% of our Marcellus shale acreage is held-by-production, providing us with a competitive advantage since we can develop the majority of our Marcellus acreage under an optimized schedule not driven by lease term expiration.

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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. 2-D seismic continues to be utilized for reconnaissance. During 2009, we drilled eight gross Marcellus shale wells primarily to test and evaluate our position.

Pennsylvania area

Our Pennsylvania area encompasses 27 counties. Drilling, completion and production activities target the Marcellus shale as well as the Upper Devonian, Venanago, Bradford and Elk sandstone groups at depths from 1,800 to 8,100 feet.

During 2010, our Marcellus development program is 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 one operated horizontal drilling rig in the play. We drilled five horizontal and three vertical Marcellus wells in the first half of 2010. Our vertical well drilling is predominately for geologic and engineering data gathering and appraisal. Our most recently completed horizontal well had a 4,800 foot lateral and an IP rate of 4.0 Mmcf per day. We recently drilled three horizontal wells from a common pad, which are scheduled for completion during the third quarter of 2010. The length of these laterals are each over 5,000 feet. For the full year 2010, we plan to drill and complete 15 gross operated horizontal wells in the play and exit 2010 with three operated horizontal drilling rigs.

West Virginia area

Our West Virginia area includes 30 counties and stretches from the northern to the southern areas of the state. Drilling, completion and production activities target the Marcellus shale and multiple, laterally stratified reservoirs of the Mississippian and Devonian formations found at depths ranging from 1,500 to 8,100 feet. During 2010, we plan to drill one gross operated vertical well and participate in one gross outside operated horizontal Marcellus drill wells.

Permian

The Permian Basin, located in West Texas and the adjoining area of southeastern New Mexico, is best known as a mature oil-focused basin exploited with waterflood and other enhanced oil recovery techniques. Our activities are focused on conventional oil and natural gas properties. With the use of 3-D seismic, we are targeting prolific reservoirs with potential for multi-pay horizons. The properties are characterized by long reserve lives and low operating costs.

Sugg Ranch Field

The Sugg Ranch Field is located primarily in Irion County, Texas. We have a total working interest of 97% in the property. Production is primarily from the Canyon Sand from depths of 6,700 to 7,900 feet. We currently plan to use two operated vertical rigs to drill and complete 53 wells in 2010.

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Midstream

We continue to expand our midstream operations, particularly in East Texas / North Louisiana. Our 50% owned midstream subsidiary, TGGT, had revenue throughput of 1.0 Bcf per day during the second quarter 2010 and currently exceeds 1.2 Bcf per day. Our efforts in the quarter included start-up of a new treating facility in Red River Parish, Louisiana with 500 Mmcf per day of Haynesville shale production capacity. The facility became fully operational in the second quarter 2010, and we plan to have a total of approximately 1.0 Bcf per day of treating capacity by year end 2010. We continue to promptly hookup and flow our newly completed wells to sales. As we have finished the major construction phase of our header and gathering system in DeSoto Parish, we are beginning to develop a similar system in the Shelby Trough area in East Texas.

Financial Data

Our consolidated balance sheets as of June 30, 2010 and December 31, 2009, consolidated statements of operations for the three and six months ended June 30, 2010 and 2009 and consolidated statements of cash flows for the six months ended June 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, August 4, 2010 at 8:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call (877) 312-5172 if you wish to participate and ask for the EXCO conference call ID# 86621656. The conference call will also be webcast on EXCO’s website at www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted on EXCO’s website on Tuesday, August 3, 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., August 18, 2010. Please call (800) 642-1687 and enter conference ID# 86621656 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 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, 2009 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 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.

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EXCO Resources, Inc.

Consolidated balance sheet

(in thousands)	June 30, 2010			December 31, 2009
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	98,027		$	68,407
Restricted cash		75,246			58,909
Accounts receivable, net:
Oil and natural gas		63,362			56,485
Joint interest		88,944			47,104
Interest and other		17,651			10,832
Inventory		12,600			15,830
Derivative financial instruments		102,507			138,120
Other		40,471			6,401
Total current assets		498,808			402,088
Equity investments		288,143			216,987
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties		622,294			492,882
Proved developed and undeveloped oil and natural gas properties		2,114,990			1,875,749
Accumulated depletion		(1,207,745	)		(1,132,604	)
Oil and natural gas properties, net		1,529,539			1,236,027
Gas gathering assets		145,954			180,506
Accumulated depreciation and amortization		(20,939	)		(22,841	)
Gas gathering assets, net		125,015			157,665
Office and field equipment, net		24,238			31,771
Deferred financing costs, net		18,756			7,602
Derivative financial instruments		39,912			34,677
Goodwill		218,256			269,656
Other assets		11,234			2,421
Total assets	$	2,753,901		$	2,358,894

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EXCO Resources, Inc.

Consolidated balance sheet

(in thousands, except per share and share data)	June 30, 2010			December 31, 2009
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	87,368		$	112,991
Revenues and royalties payable		106,693			79,356
Accrued interest payable		16,302			16,193
Current portion of asset retirement obligations		900			900
Income taxes payable		5,210			210
Derivative financial instruments		639			3,264
Current maturities of long-term debt		446,831			—
Total current liabilities		663,943			212,914
Long-term debt, net of current maturities		477,500			1,196,277
Deferred income taxes		—			—
Derivative financial instruments		5,648			11,688
Asset retirement obligations and other long-term liabilities		60,327			78,427
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; authorized shares - 350,000,000; issued and outstanding shares - 212,648,328 at June 30, 2010 and 211,905,509 at December 31, 2009		213			212
Additional paid-in capital		3,124,991			3,105,238
Accumulated deficit		(1,578,721	)		(2,245,862	)
Total shareholders’ equity		1,546,483			859,588
Total liabilities and shareholders’ equity	$	2,753,901		$	2,358,894

12

EXCO Resources, Inc.

Consolidated statement of operations

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(in thousands, except per share data)	2010			2009			2010			2009
Revenues:
Oil and natural gas	$	118,344		$	146,252		$	249,338		$	318,460
Midstream		—			12,942			—			29,955
Total revenues		118,344			159,194			249,338			348,415
Costs and expenses:
Oil and natural gas production		31,024			48,394			58,082			101,512
Midstream operating		—			11,719			—			30,169
Gathering and transportation		12,873			4,055			23,986			7,952
Depreciation, depletion and amortization		45,339			55,180			84,157			136,974
Write-down of oil and natural gas properties		—			—			—			1,293,579
Accretion of discount on asset retirement obligations		1,001			2,018			2,090			4,089
General and administrative		25,866			22,488			52,285			43,035
Gain on divestures and other operating items		(574,946	)		8,382			(575,353	)		7,977
Total costs and expenses		(458,843	)		152,236			(354,753	)		1,625,287
Operating income (loss)		577,187			6,958			604,091			(1,276,872	)
Other income (expense):
Interest expense		(14,476	)		(46,891	)		(25,110	)		(83,023	)
Gain (loss) on derivative financial instruments		707			(31,017	)		99,856			190,367
Other income		57			13			117			35
Equity income		5,290			—			5,379			—
Total other income (expense)		(8,422	)		(77,895	)		80,242			107,379
Income (loss) before income taxes		568,765			(70,937	)		684,333			(1,169,493	)
Income tax expense		4,452			1,055			4,452			2,110
Net income (loss)	$	564,313		$	(71,992	)	$	679,881		$	(1,171,603	)
Earnings (loss) per common share:
Basic
Net income (loss)	$	2.66		$	(0.34	)	$	3.20		$	(5.55	)
Weighted average common shares outstanding		212,497			211,089			212,293			211,042
Diluted
Net income (loss)	$	2.62		$	(0.34	)	$	3.15		$	(5.55	)
Weighted average common and common equivalent shares outstanding		215,498			211,089			215,520			211,042

13

EXCO Resources, Inc.

Consolidated statement of cash flows

(Unaudited)

	Six months ended June 30,
(in thousands)	2010			2009
Operating Activities:
Net income (loss)	$	679,881		$	(1,171,603	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		84,157			136,974
Stock option compensation expense		8,463			6,480
Accretion of discount on asset retirement obligations		2,090			4,089
Write-down of oil and natural gas properties		—			1,293,579
Gain on divestitures		(574,878	)
Income from equity investments		(5,379	)		—
Non-cash change in fair value of derivatives		21,711			46,196
Cash settlements of assumed derivatives		907			(90,294	)
Deferred income taxes		—			2,110
Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011		3,847			23,767
Effect of changes in:
Accounts receivable		(65,218	)		27,300
Other current assets		(4,081	)		(3,497	)
Accounts payable and other current liabilities		30,353			(48,168	)
Net cash provided by operating activities		181,853			226,933
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(263,361	)		(267,405	)
Property acquisitions		(438,382	)		(62,963	)
Restricted cash		(16,337	)		(37,500	)
Deposit on pending divestitures		—			57,688
Investment in equity investments		(68,500	)		—
Proceeds from disposition of property and equipment		956,296			55,783
Advances to Appalachia JV		(30,448	)		—
Net cash provided by (used in) investing activities		139,268			(254,397	)
Financing Activities:
Borrowings under credit agreements		1,352,399			52,949
Repayments under credit agreements		(1,622,463	)		(22,740	)
Proceeds from issuance of common stock		9,091			1,648
Payment of common stock dividends		(12,740	)		—
Settlements of derivative financial instruments with a financing element		(907	)		90,294
Deferred financing costs and other		(16,881	)		(20,468	)
Net cash provided by (used in) financing activities		(291,501	)		101,683
Net increase in cash		29,620			74,219
Cash at beginning of period		68,407			57,139
Cash at end of period	$	98,027		$	131,358
Supplemental Cash Flow Information:
Cash interest payments	$	25,520		$	72,718
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	2,175		$	1,180
Capitalized interest	$	6,114		$	2,797
Issuance of common stock for director services	$	25		$	35

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)	2010			2009			2010			2009
Net income (loss)	$	564,313		$	(71,992	)	$	679,881		$	(1,171,603	)
Interest expense		14,476			46,891			25,110			83,023
Income tax expense		4,452			1,055			4,452			2,110
Depreciation, depletion and amortization		45,339			55,180			84,157			136,974
EBITDA(1)		628,580			31,134			793,600			(949,496	)
Accretion of discount on asset retirement obligations		1,001			2,018			2,090			4,089
Non-cash write-down of oil and natural gas properties		—			—			—			1,293,579
Gain on divestitures		(574,878	)		—			(574,878	)		—
Equity method income		(5,290	)		—			(5,379	)		—
Non-cash change in fair value of derivative financial instruments		45,831			173,156			23,729			50,201
Stock based compensation expense		3,854			3,257			8,463			6,480
Adjusted EBITDA (1)	$	99,098		$	209,565		$	247,625		$	404,853
Interest expense (2)		(14,476	)		(45,110	)		(27,128	)		(87,028	)
Income tax expense		(4,452	)		(1,055	)		(4,452	)		(2,110	)
Amortization of deferred financing costs, premium on 7 1/4% senior notes due 2011 and discount on long-term debt		3,937			12,009			3,847			23,767
Deferred income taxes		—			1,055			—			2,110
Changes in operating assets and liabilities		6,443			(2,179	)		(38,946	)		(24,365	)
Settlements of derivative financial instruments with a financing element		—			(52,678	)		907			(90,294	)
Net cash provided by operating activities	$	90,550		$	121,607		$	181,853		$	226,933

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2010			2009			2010			2009
Statement of cash flow data (unaudited):
Cash flow provided by (used in):
Operating activities	$	90,550		$	121,607		$	181,853		$	226,933
Investing activities		263,088			(69,882	)		139,268			(254,397	)
Financing activities		(303,415	)		34,125			(291,501	)		101,683
Other financial and operating data:
EBITDA(1)		628,580			31,134			793,600			(949,496	)
Adjusted EBITDA(1)		99,098			209,565			247,625			404,853

(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, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, stock-based compensation and equity method income in TGGT and other equity 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 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 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.

15

(2) Excludes non-cash changes in fair value of $0 and $1.8 million for the three months ended June 30, 2010 and 2009, respectively, and $2.0 million and $4.0 million for the six months ended June 30, 2010 and 2009, respectively, for 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,				%
	2010		2009		Change		2010		2009		Change
Production:
Oil (Mbbls)		168		485	-65	%		327		1,012	-68	%
Gas (Mmcf)		25,539		33,608	-24	%		48,376		66,792	-28	%
Oil and natural gas (Mmcfe)		26,547		36,518	-27	%		50,338		72,864	-31	%
Average sales prices (before derivative financial instrument activities):
Oil (per Bbl)	$	74.44	$	56.08	33	%	$	74.83	$	46.34	61	%
Gas (per Mcf)		4.14		3.54	17	%		4.65		4.07	14	%
Total production (per Mcfe)		4.46		4.00	12	%		4.95		4.37	13	%
Average costs (per Mcfe):
Oil and natural gas operating costs	$	0.85	$	1.07	-21	%	$	0.83	$	1.09	-24	%
Production and ad valorem taxes		0.32		0.26	23	%		0.33		0.30	10	%
Gathering and transportation costs		0.48		0.11	336	%		0.48		0.11	336	%
Depletion		1.55		1.32	17	%		1.49		1.69	-12	%
Depreciation and amortization		0.16		0.19	-16	%		0.18		0.19	-5	%
General and administrative		0.97		0.62	56	%		1.04		0.59	76	%

17