EXCO Resources, Inc. Reports First Quarter 2010 Results

EXCO Resources, Inc. (NYSE:XCO) today announced its first quarter 2010 results of operations. Highlights during the quarter include:

- Adjusted net income available to common shareholders, a non-GAAP measure adjusting for unrealized derivative gains and losses, non-cash ceiling test write-downs and other non-cash items typically not included by securities analysts in published estimates, was $0.25 per share for the first quarter 2010 compared with $0.19 per share for the first quarter 2009.

- Oil and natural gas production was 23.8 Bcfe, reflecting daily production of 264 Mmcfe per day, for the first quarter 2010 compared with 21.4 Bcfe (237 Mmcfe per day) pro forma first quarter 2009 production, which eliminates volumes attributable to properties sold during 2009 and the impact of our August 2009 joint venture with BG Group in East Texas/North Louisiana ("BG Upstream Transaction"). The following table presents the current quarter’s production and the prior year’s first quarter production on an actual and pro forma basis:

- Net production from our Haynesville shale operations was 8.7 Bcf (97 Mmcf per day), or 37% of our total production during the first quarter 2010 compared with only 10 Mmcf per day, or 4% of our total production, in the pro forma first quarter 2009. Current net Haynesville volumes exceed 120 Mmcf per day. During the first quarter 2010, we spud 22 operated Haynesville wells and completed 19 operated wells with an average initial production ("IP”) rate of approximately 21 Mmcf per day. We calculate our IP as the highest 24-hour production rate during the flow back period. We continue to drill and complete some of the strongest wells in the field. During the first quarter 2010, we drilled our first horizontal Bossier test well and completed this well early in the second quarter 2010 with an IP of approximately 11 Mmcf per day. We also participated in 16 non-operated Haynesville wells spud during the first quarter 2010.

- Oil and natural gas revenues for the first quarter 2010 were $131 million, exclusive of the impacts of derivative financial instruments (derivatives), compared with the first quarter 2009 oil and natural gas revenues of $172 million. The lower revenues were due primarily to the impacts from our 2009 divestitures and joint venture transactions, and were partially offset by higher realized prices for natural gas, which increased by 13% from the prior year’s first quarter and higher oil prices, which more than doubled. When the impacts of cash settlements from our oil and natural gas derivatives are considered, the oil and natural gas revenues, as adjusted, were $208 million for the first quarter 2010 compared with $271 million for the first 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 first quarter 2010 was $149 million, which includes $38 million of proceeds attributable to unwinding of oil and natural gas derivatives, compared with $195 million in the first quarter 2009.

- On April 21, 2010, we announced an agreement to purchase Common Resources, L.L.C. ("Common”) jointly with BG Group for $446 million in cash ($223 million net to EXCO) subject to customary purchase price adjustments. This acquisition will add approximately 29,200 net acres to the joint venture with BG (14,600 net acres to EXCO) and is expected to close in May 2010. This acquisition provides an entry into the Shelby Trough area of the Haynesville/Bossier shale play in Shelby, San Augustine and Nacogdoches Counties, Texas. Initial industry results in the area are very encouraging in both the Haynesville and Bossier shales, with Haynesville shale IP rates comparable to those being reached by EXCO in DeSoto Parish, Louisiana.

- On April 30, 2010, we consolidated our revolving credit agreements into one facility, with a borrowing base of $1.3 billion. As of the date of consolidation, we had $818 million outstanding under the facility leaving $467 million of availability.

- In light of current natural gas prices and our recently announced acquisition of Common, we will be reevaluating 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 will defer much of our drilling in the Haynesville shale in Harrison County, Texas and northern Caddo Parish, Louisiana where we have substantially all of our acreage held-by-production. The IPs and returns in these areas have been lower than in southern Caddo and DeSoto Parishes, Louisiana. In this environment, we will continue searching for opportunities to expand our acreage positions in our shale plays.

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

"The first quarter of 2010 was another successful and productive quarter for EXCO. We continued the successful Haynesville and Bossier shale development in East Texas/North Louisiana, completing 19 additional operated Haynesville wells with average IP rates over 20 Mmcf per day and completing our first successful Bossier well. We drilled one horizontal Marcellus well, and have since completed two horizontal wells with encouraging results. We continued to expand our acreage positions in the Haynesville and Marcellus plays and also reached an agreement on the Common acquisition, which will add nearly 15,000 additional net acres to our portfolio.

Our capital spending program is expected to be funded by cash flow, and the new credit facility provides us with capital to continue adding to our acreage positions in our shale plays. Since the majority of our acreage is held-by-production, we also have a tremendous amount of flexibility in our capital program. Our announced acquisition of Common is a great example. The current economic environment created an opportunity for us to acquire a significant acreage position at an attractive price. As a result of our 2009 transactions, we have ample liquidity to fund this acquisition and, because our legacy assets are being held-by-production, we have the flexibility to move existing rigs to the Common acreage without increasing our activity level. We are currently evaluating our drilling plans for the remainder of 2010 as a result of current commodity prices and in anticipation of closing the Common acquisition.

We are very optimistic about the remainder of 2010; however, we are cautious due to the continuing weakness in natural gas prices and the high cost of certain drilling and completion services. As a result, we have deferred drilling in parts of the Haynesville play where we do not believe we can generate an appropriate rate of return. We continue to monitor our capital spending and will make adjustments depending on economics by area.”

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:

(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 and dilutive stock options outstanding.

Cash Flow

First 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 $136 million, an 18% decrease from the prior year’s first quarter due primarily to lower 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.

(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 $65 million on development and exploitation activities, drilling and completing 42 gross (18.8 net) wells in the first quarter 2010, compared with 22 gross (10.2 net) wells during the fourth quarter 2009. We had an overall drilling success rate of 98% for the first quarter 2010, as we completed 42 of the 43 wells drilled. We are successfully continuing efforts to acquire additional leasehold in our shale areas. Our total capital expenditures, including leasing, midstream and corporate activities, were $130 million in the first quarter 2010. We also made equity contributions into TGGT of $45 million and received $67 million of proceeds from asset sales, primarily as reimbursements from BG Group pursuant to the BG AMI.

As commodity prices remain under pressure, we are continuing to evaluate our drilling plans to ensure we meet our internal return targets. We currently have 24 drilling rigs operating across our portfolio, of which 16 are operated. Our projected capital spending for 2010 is presented on the following table:

East Texas/North Louisiana

East Texas/North Louisiana is our largest division in terms of production and reserves, which is primarily attributable to our expansion in the Haynesville shale play. Our 2010 budget for the division totals $255 million, with $142 million allocated to Haynesville shale activities (primarily drilling and completion activity). Our spending remains low relative to our activity level as BG Group continues to carry 75% of our net drilling and completions costs in the Haynesville and Bossier shales. At the end of the first quarter 2010, the remaining balance of the BG Carry was $313.8 million. In East Texas/North Louisiana, we drilled and completed 32 gross (9.1 net) wells in the first quarter 2010.

Haynesville/Bossier Shale

During the first quarter 2010, our horizontal Haynesville shale development program continued to yield exceptional results with some of the highest production rates in the play. We drilled and completed 19 gross operated horizontal (6.4 net) Haynesville wells during the first quarter 2010. We utilized 13 operated drilling rigs to spud 22 operated horizontal wells. We also participated in 16 non-operated horizontal wells. We currently have 51 operated horizontal wells and 40 non-operated horizontal wells flowing to sales. Production from our operated Haynesville and Bossier wells is currently 380 Mmcf per day gross (112 Mmcf per day net). Assuming we continue to realize acceptable economic returns, we plan to complete between 20 and 30 Haynesville wells per quarter over the remainder of 2010. In addition to our operated rigs, we currently have eight non-operated rigs drilling in the play. We drilled our first horizontal Bossier well during the first quarter 2010 and completed it early in the second quarter 2010, with an approximate 11 Mmcf per day IP rate from a 13 stage frac. We plan to drill up to six more horizontal Bossier wells in DeSoto Parish during 2010 to test the play.

The average IP rate from all of our operated Haynesville horizontal wells in DeSoto Parish continues to be approximately 23 Mmcf per day. This high level of performance over a broad area underscores the consistency and high quality of the shale reservoir on our acreage and also demonstrates the effectiveness of our target selection and completion design.

We are now testing various drilling and completion methods to improve our recoveries and reduce our costs. These methods include pad drilling, spacing tests, frac sizes and cluster spacing as well as different types and combinations of proppant. While we continue to have access to the services necessary to support our operations, we have seen increasing costs.

Appalachia

In February 2010 we deployed a horizontal drilling rig in Pennsylvania and intend to continuously operate this rig throughout 2010 and beyond. Having this dedicated rig will allow our drilling performance to continually improve. We drilled one Marcellus shale horizontal well during the first quarter 2010 and currently plan to drill a total of 11 gross (11.0 net) operated horizontal wells and participate in four gross non-operated horizontal drill wells in the Marcellus shale during the year. We are also negotiating to contract at least two additional fit-for-purpose rigs under long-term contracts beginning later in 2010 as we are targeting a minimum of a three rig program for 2011.

Our top priorities in Appalachia include evaluating our existing leasehold to determine the best areas and techniques for Marcellus shale development and growing our acreage position in the key identified, potential shale development areas. Our land strategy is to build contiguous acreage positions that lend themselves to development of the Marcellus shale using multi-well pad operations. We also continue to pursue joint venture opportunities to enhance our development and increase the value of our Appalachian assets.

We completed two operated Marcellus shale horizontal wells early in the second quarter 2010, with IP rates in excess of 2.2 and 2.3 Mmcf per day, respectively. The first well was completed with an 8-stage frac across its planned 2,500 foot lateral section. The second well was drilled to a lateral length of 4,600 feet but we identified damage to the casing at a point approximately 2,600 feet into the lateral section. We elected to initially complete only across the first 2,500 feet of the lateral, using 8 frac stages. Following our analysis of the productivity from this interval, we will consider completing the well across the remaining lateral section later this year. We expect IP rates to increase as we drill and complete wells with longer lateral lengths.

Permian

We drilled and completed 10 gross (9.7 net) wells in our Permian area Canyon Sand field during the first quarter 2010. We also drilled one exploratory well which was a dry hole to test an oil formation in Dickens County, Texas. Our overall drilling success rate in the Permian area during the first quarter 2010 was 91%. We had one rig running in the Canyon Sand field at the end of the first quarter 2010.

Midstream

We continue to expand our midstream operations, particularly in East Texas / North Louisiana. Our 50% owned midstream subsidiary, TGGT, had revenue throughput of 826 Mmcf per day during the first quarter 2010 and currently exceeds 900 Mmcf per day. Our efforts in the quarter included construction of a new facility in Red River Parish, Louisiana to treat 500 Mmcf per day of Haynesville shale production. The facility will be 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.

Financial Data

Our consolidated balance sheets as of March 31, 2010 and December 31, 2009, consolidated statements of operations for the three months ended March 31, 2010 and 2009 and consolidated statements of cash flows for the three months ended March 31, 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, May 5, 2010 at 8:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call 800-309-5788 if you wish to participate and ask for the EXCO conference call ID# 68715658. 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, May 4, 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., May 19, 2010. Please call 800-642-1687 and enter conference ID# 68715658 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.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this presentation, and the risk factors included in the Annual Report on Form 10-K for the year ended December 31, 2009 and our other periodic filings with the SEC.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

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.

(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 Holdings, LLC. 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 revolving and term 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 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 changes in fair value of $2.0 million and $5.8 million for the three months ended March 31, 2010 and 2009, respectively, for interest rate swaps included in GAAP interest expense.