Exhibit 99.1

EXCO RESOURCES, INC. REPORTS SECOND QUARTER 2011 RESULTS

DALLAS, TEXAS, August 2, 2011…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced second quarter results for 2011.

Our second quarter 2011 operating and financial results reflect our continued success in the Haynesville/Bossier shale area and further expansion and refinement of opportunities in our Marcellus shale operations. During the quarter, we closed an acquisition of mineral interests, land and other assets in our core DeSoto Parish area and continued with our 27 operated drilling rig program consisting of 22 rigs in the Haynesville/Bossier shale, three in Appalachia and two in our Permian area. Our production and cash flows are increasing and our capital expenditure program can be executed with cash flow and available borrowing capacity from our credit agreement. Our financial results for the second quarter 2011 follow.

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Douglas H. Miller, EXCO’s Chief Executive Officer commented “Our exceptional results for the quarter highlight the quality of our asset base and employees. Despite curtailed production during the quarter resulting from the TGGT treating facility incident, our daily production grew by 71% year-over-year and 23% from the first quarter of 2011. We continue to see strong Haynesville shale results in our DeSoto Parish position where we are in full manufacturing mode. In our Shelby area, we realized IP’s of over 28 Mmcf per day in the Haynesville shale and 25 Mmcf per day in the Bossier shale as we further delineate that acreage. Our results in the Marcellus shale continue to improve and we expect to increase our level of activity as a result. We are focused on managing both capital costs and operating expenses across our portfolio, in addition to increasing our positions in both the Haynesville/Bossier and Marcellus shales. Including cash on hand and our unused borrowing base, we have approximately $777 million of liquidity to fund our capital program and acreage acquisition efforts. With our extensive drilling inventory, we continue to expect substantial production growth for the remainder of 2011 and in future years while continuing to manage our balance sheet.”

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Net income

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

Cash flow and financing transactions

Our cash flow from operations before working capital changes, a non-GAAP measure, was $152 million for the second quarter 2011. We use our cash flow, credit agreement and proceeds from selected divestitures to fund drilling and development programs.

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Redetermination of borrowing base

On April 1, 2011, the lenders under our revolving credit agreement completed their regular semi-annual redetermination of the borrowing base, resulting in an increase of the borrowing base from $1.0 billion to $1.5 billion. In addition, the interest rate under the credit agreement was reduced by 50 basis points (bps) and the maturity date was extended from April 30, 2014 to April 1, 2016. The next redetermination of the borrowing base is scheduled to occur on October 1, 2011.

As of July 27, 2011, $852 million was drawn under our credit agreement and we had $138 million of cash, which includes $106 million of restricted cash. Our available borrowing under our credit agreement as of July 27, 2011, including cash and restricted cash on hand was $777 million.

Operations activity and outlook

We spent $241 million on development and exploitation activities, drilling and completing 71 gross (40.6 net) operated wells in the second quarter 2011, compared with 65 gross (36.1 net) operated wells during the first quarter 2011. In addition, we participated in 20 gross (0.8 net) wells operated by others (OBO) during the second quarter 2011. We had an overall drilling success rate of 99% for the second quarter 2011. Our total capital expenditures, including leasing and net of acreage reimbursements from BG Group, were approximately $260 million in the second quarter 2011. We are continuing efforts to opportunistically acquire additional leasehold in our core shale areas.

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

In addition to our capital program, we closed on $113 million, net to EXCO, of acquisitions during the second quarter 2011.

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Haynesville/Bossier Shale

Our horizontal Haynesville shale development program continues to yield outstanding results. As of July 25, 2011, our Haynesville/Bossier operated production was 1,173 Mmcf per day gross (365 Mmcf per day net) and with the addition of our OBO wells, we had 391 Mmcf per day of net production. Our development program in DeSoto Parish, Louisiana is focused on manufacturing on 80-acre spacing. Our program in San Augustine and Nacogdoches Counties, Texas is focused on delineation and testing of our acreage. During 2011, we plan to drill 241 gross (70.1 net) wells in the Haynesville/Bossier shale play in East Texas/North Louisiana. Of these 241 wells, 171 gross wells are operated by EXCO.

We drilled and completed 47 gross (20.4 net) operated horizontal Haynesville and Bossier wells and participated in 20 gross (0.8 net) OBO Haynesville horizontal wells during the second quarter of 2011. We utilized 22 operated rigs and spud 42 operated horizontal wells. In addition to our operated rig count, we typically have 3-6 OBO rigs drilling in the play. During the quarter, 11 OBO wells were spud. We currently have 232 operated horizontal wells and 123 OBO horizontal wells flowing to sales.

The average initial production rate (“IP”) during the quarter from all of our operated Haynesville horizontal wells in DeSoto Parish was 18 Mmcf per day on a managed drawdown/restricted choke program. Our manufacturing approach for simultaneous drilling followed by simultaneous completions by unit is being successfully implemented. We currently have 15 units fully drilled, completed and flowing to sales on 80-acre spacing and expect to have 25 units fully developed by year end. This high level of sustained performance in our 80-acre development program underscores the quality and consistency of our shale assets. We have a strong focus on the capital efficiencies of our drilling and completion programs. The design changes and manufacturing efficiency gains in both the drilling phase and the completion phase of our wells should result in an overall well cost reduction of approximately 7% compared to our actual costs incurred in the first half of 2011. These improvements are the result of more efficient pad and road utilization and construction processes, design changes with drill bit technology resulting in higher rates of penetration and a more efficient completion design and implementation process, among others.

We acquired the assets in our Shelby area in May 2010. At the time of acquisition, the area total production rate was 34 Mmcf per day gross from eight operated wells. Our Shelby area is currently producing 222 Mmcf per day gross from a total of 39 operated wells. Results from our testing and delineation program in our Shelby area are encouraging. In the quarter we completed four wells in the deeper part of the play in Nacogdoches County, Texas with average IP rates of 29 Mmcf per day with average flowing pressures of 9,566 psi on 28/64ths chokes. The wells in this area are just over 19,400 feet measured depth with an average completed lateral length of 4,600 feet. These wells are performing above our original expectations. We drilled and completed our first horizontal Middle Bossier test well in San Augustine County during the first quarter 2011 with an IP rate of 26 Mmcf per day from a 16 stage fracture stimulation treatment. The Middle Bossier performance is also above our original expectations. We currently have two Middle Bossier test wells drilling and a total of eight operated rigs running in the Shelby area.

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Marcellus Shale

We are implementing a development program within our recently acquired acreage in northeast Pennsylvania. We are also implementing an appraisal program across much of our other acreage, primarily in central Pennsylvania. We spud seven new operated wells and drilled and completed 6 gross (2.7 net) operated wells during the second quarter 2011 in the Marcellus shale. The IP rates of these wells ranged from 2 Mmcf per day to over 5 Mmcf per day from lateral lengths between 3,200 feet and 5,000 feet. In all of EXCO’s operating areas, we disclose IP as the peak 24-hour production rate during our first few days of flowback. However, in Appalachia, we have wells that realize peak production rates approximately one to two months after initial production, as the wells unload water, flowback is managed and tubing is installed. In certain areas, we have realized an average rate increase of 50-75% between the first seven days of production and the peak production rate. We continue to evaluate reservoir performance to optimize our development plans.

We plan to drill 49 gross (16.0 net) operated wells in the Marcellus shale play in our Appalachia region during 2011. Of the 49 wells, 42 gross (12.8 net) will be development wells and 7 gross (3.2 net) will be appraisal wells. This drilling will be within the Appalachia JV area, so our net drilling dollars are reduced by the effect of the carry we receive from BG Group. Approximately $98 million of the carry remains available to us from BG Group as of June 30, 2011. We expect that the remaining carry amount will be used by the end of 2011. We are currently drilling with three operated rigs and we plan to exit 2011 with 4-5 operated drilling rigs in Appalachia.

Permian

We drilled and completed 18 gross (17.5 net) wells in our Permian area Canyon Sand field during the second quarter 2011 with 95% drilling success as one of our wells was a dry hole. We continue to run two operated rigs in the Canyon Sand field and plan to drill 72 gross (69.8 net) wells in 2011. Oil production at Sugg Ranch has increased by 17% in the second quarter of 2011 as compared to the second quarter of 2010, and economics for this drilling activity typically have rates-of-return in excess of 50%.

Midstream

Through our jointly held midstream company, TGGT, we continue our major infrastructure expansion efforts in our Shelby Trough area of east Texas in order to meet the expected throughput volume increase. We are also continuing to develop our gathering and treating capacity in the DeSoto Parish area of northwest Louisiana. Total throughput for TGGT averaged approximately 1.4 Bcf per day for the second quarter of 2011 compared with total average throughput of 1.2 Bcf per day in the first quarter 2011. Despite the volumetric reductions from the May 28, 2011 incident discussed below, our current throughput as of July 25, 2011 was approximately 1.5 Bcf per day.

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On May 28, 2011, an incident occurred at a TGGT amine treating facility in northwest Red River Parish, Louisiana resulting in an immediate shut-down of the facility. As a precautionary measure, TGGT also shut down another amine treating facility located in DeSoto Parish with similar specifications. While TGGT has an ongoing investigation into causes of the incident, they have ordered temporary treating units and expect resumption of treating capacity during the third quarter of 2011, with a total resumption of treating facilities during the fourth quarter of 2011. The estimated second quarter 2011 impact to TGGT resulting from this incident was a $4 million net decrease to their operating income and the anticipated impact for the remainder of the year is a $10 million decrease in their operating income. In addition, TGGT recorded an impairment charge to the damaged facility of approximately $12 million in the second quarter of 2011. The majority of this charge is expected to be offset in the future by insurance proceeds.

Financial Data

Our consolidated balance sheets as of June 30, 2011 and December 31, 2010 and consolidated statements of operations for the three and six months ended June 30, 2011 and 2010, and consolidated statements of cash flows for the six months ended June 30, 2011 and 2010, 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 3, 2011 at 9:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call (800) 309-5788 if you wish to participate, and ask for the EXCO conference call ID# 83127029. 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 2, 2011, after market close.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., August 17, 2011. Please call (855) 859-2056 and enter conference ID# 83127029 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, as amended, for the year ended December 31, 2010, 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, as amended, for the year ended December 31, 2010, 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

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EXCO Resources, Inc.

Consolidated balance sheet

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EXCO Resources, Inc.

Consolidated statement of operations

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EXCO Resources, Inc.

Consolidated statement of cash flows

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EXCO Resources, Inc.

Consolidated EBITDA

And adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)

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EXCO Resources, Inc.

Summary of operating data