EXCO Resources, Inc. Reports First Quarter 2009 Results

EXCO Resources, Inc. (NYSE: XCO) today announced its first quarter 2009 results of operations. Highlights during the quarter include:

• Oil and natural gas production was 36.3 Bcfe, reflecting record daily production of 404 Mmcfe per day for the first quarter 2009 compared with 35.1 Bcfe (386 Mmcfe per day) during the first quarter 2008. This record daily production was achieved despite decreases in drilling and completion activity due to low commodity prices. Net production from our Haynesville shale drilling contributed 1.9 Bcf (21 Mmcf per day) for the first quarter 2009 from three producing horizontal wells drilled during the fourth quarter 2008 and first quarter 2009 and nine vertical test wells drilled during 2008. Our current net production from the Haynesville shale, including wells completed in April, exceeds 45 Mmcf per day.
• Oil and natural gas revenues for the first quarter 2009 were $172 million, exclusive of the impacts of derivative financial instruments (derivatives), compared with the first quarter 2008 oil and natural gas revenues of $325 million. The lower revenues reflect realized price declines of 47% for natural gas and 61% for oil from the prior year’s first quarter. When the impacts of cash settlements from our oil and natural gas derivatives are considered, the oil and natural gas revenues, as adjusted, would have been $271 million for the first quarter 2009 compared with $328 million for the first quarter 2008.
• 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 $0.19 per share for the first quarter 2009 compared with $0.28 per share for the first quarter 2008 and $0.13 per share during the fourth quarter 2008.
• 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 2009 was $195 million compared with $254 million in the first quarter 2008.
• Midstream operating profit, before the effect of intercompany eliminations, was $7 million for the first quarter 2009, equal to the prior year’s first quarter.
• Our first quarter 2009 loss was negatively impacted by net non-cash after-tax losses of approximately $1.3 billion representing ceiling test write-downs and income tax valuation allowances, which were partially offset by unrealized gains on derivatives, resulting in a GAAP loss of $1.1 billion. See our Net Income section, which presents details for each of the aforementioned significant non-cash items. Our ceiling test write-down in the first quarter 2009 was based on March 31, 2009 cash spot market prices of $3.63 per Mmbtu for natural gas and $49.64 per Bbl of oil computed in accordance with current guidelines established by the Securities and Exchange Commission (SEC). Recently, the SEC issued new rules related to disclosure of oil and natural gas reserves and the computation of the ceiling test for companies that follow the full cost method of accounting. These new rules, which do not take effect until the end of 2009, will change the prices utilized in our SEC reserve estimates and will use an average cash spot market price based on the first day of each month over the trailing twelve month period rather than the cash spot market price at the end of each quarter. None of the aforementioned non-cash items affect our liquidity or compliance with bank covenants.
• In light of the continuing price declines in natural gas, we have adjusted our capital expenditure program and are effectively limiting our capital projects to Haynesville shale drilling, limited drilling in the Marcellus shale in Appalachia and midstream pipeline projects to facilitate delivery of Haynesville volumes. Our approved capital budget for 2009 is $582 million, of which $326 million is for drilling and completion. We presently expect to reduce our budget needs to approximately $500 million, of which $266 million is for drilling and completion.

Douglas H. Miller, EXCO’s Chairman and CEO, commented, "I’m very pleased with the progress we have made toward our goals of managing our spending, accelerating our development of the Haynesville shale and strengthening our balance sheet. We have completed six operated horizontal wells in the Haynesville shale and results have been outstanding. Our first five wells in DeSoto Parish averaged initial production rates of almost 24 Mmcf per day, with one recent completion exceeding 26 Mmcf per day. Our first Caddo Parish well is one of the best in the area, with an initial production rate of nearly 9 Mmcf per day. These results have been accomplished while reducing our drilling days from 75 days to less than 50 days in some cases. We reaffirmed our borrowing base at nearly $2.5 billion, have initiated a sales effort on non-core properties and continue to pursue joint venture opportunities in our Haynesville shale area, including the midstream operations. During the remainder of 2009, we will continue to aggressively develop the Haynesville, will continue to ramp up our activity in the Marcellus shale in Appalachia and focus on our balance sheet. With our current asset base and our success in the Haynesville shale we expect to maintain and grow our production despite our reduced drilling activity in other areas. Our cash flow for 2009 and 2010 will be greatly enhanced by our strong hedge position and the positive results from our drilling program.”

Net Income

Our reported net loss and net 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 and adjusted net income available to common shareholders 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 GAAP net income measures. The following table provides a reconciliation of our net loss and net loss available to common shareholders to non-GAAP measures of adjusted net income and adjusted net income available to common shareholders:

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

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

Cash Flow

First quarter 2009 cash flow from operations before changes in working capital and settlements of derivative financial instruments with a financing element (adjusted cash flow) was $165 million, a 26% decrease from the prior year’s first quarter due primarily to lower product prices. 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 $113 million on development and exploitation activities, drilling and completing 34 gross (27.9 net) wells in the first quarter 2009, compared with 118 gross (99.5 net) wells during the fourth quarter 2008. We had an overall drilling success rate of 94% for the first quarter 2009, as we completed 34 of the 36 wells drilled. Our total capital expenditures, including leasing, midstream and corporate activities, were $152 million in the first quarter 2009. As commodity prices continued declining, we continued to reduce our drilling activities. We currently have 8 drilling rigs operating across our portfolio, which we have reduced from 32 drilling rigs late in the third quarter 2008 in response to lower commodity prices. Anticipated 2009 capital spending, when compared with 2008, on drilling and leasing in our exploration and production operations is reduced in all operating areas while midstream capital has been increased as we begin building additional throughput in the East Texas/North Louisiana area. Our 2008 actual capital spending by significant operating areas, our original 2009 capital budget and our expected 2009 capital budget are presented on the following table. We will continue to defer capital projects that do not meet our economic return criteria.

We are continuing with plans to sell certain non-core assets during 2009. We completed asset sales of approximately $21 million through April 2009. We also continue to pursue joint venture opportunities. Proceeds of all sales or joint ventures will be used to reduce debt and allow more capital to be focused on our shale development and other activities.

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 have continued to drill and exploit these formations, we are reducing most of this activity in response to low commodity prices, but we are increasing emphasis and expanding activity in our Haynesville shale play position. Our 2009 budget for the division totals $284 million, with $189 million allocated to Haynesville shale activities (primarily drilling and completion activity). In East Texas/North Louisiana, we drilled and completed 21 gross (16.8 net) wells in the first quarter 2009.

Haynesville Shale

During the first quarter 2009, our horizontal Haynesville Shale development program yielded exceptional results with some of the highest production rates in the play. We also achieved significant improvements in operational efficiencies. We drilled and completed 3 gross horizontal (2.9 net) Haynesville wells during the first quarter 2009. We utilized four operated drilling rigs and one operated spudder rig in the quarter, and we spud seven operated horizontal wells and two non-operated horizontal wells. We currently have six operated horizontal wells and two non-operated horizontal wells flowing to sales. Production from our Haynesville wells recently reached a combined gross rate of 96 Mmcf per day (48 Mmcf per day net). In addition to our operated rigs, we currently have one non-operated rig drilling in the play. We will add three additional operated horizontal rigs by mid 2009, bringing our operated horizontal rig count to seven, and we remain on schedule to drill 34 horizontals (27 operated) in 2009. A brief summary of our achievements to date are shown below:

EXCO Operated Horizontal Wells

• Oden 30 H #6 (100% WI) DeSoto Parish, Louisiana - Initial production (IP) 22.9 Mmcf per day, 7,800 psi on 26/64ths choke in December 2008. Produced 1.0 Bcf in first 64 days. Currently flowing 8.9 Mmcf per day with 4,200 psi after 149 days with cumulative production of 1.9 Bcf.
• Lattin 24 #4 (92.8% WI) DeSoto Parish, Louisiana - IP 24.2 Mmcf per day, 7,350 psi on 26/64ths choke in February 2009. Produced 1.0 Bcf in first 67 days. Currently flowing 10.8 Mmcf per day with 5,200 psi after 82 days with cumulative production of 1.2 Bcf.
• Sammo Partnership 18 #5 (100% WI) DeSoto Parish, Louisiana - IP 21.4 Mmcf per day, 6,870 psi on 30/64ths choke in February 2009. Currently flowing 9.8 Mmcf per day with 4,800 psi after 63 days with cumulative production of 789 Mmcf.
• Sharp 1 #1 (74.3% WI) Caddo Parish, Louisiana - IP 8.6 Mmcf per day, 4,100 psi on 30/64ths choke in April 2009. Currently flowing 4.2 Mmcf per day with 4,700 psi after 19 days with cumulative production of 104 Mmcf.
• Moran 27 #6 (45.0% WI) DeSoto Parish, Louisiana - IP 26.1 Mmcf per day, 7,300 psi on 28/64ths choke in April 2009. Currently flowing 19.0 Mmcf per day with 7,150 psi after 11 days with cumulative production of 233 Mmcf.
• Cook 28 #1 (69.8% WI) DeSoto Parish, Louisiana - IP 24.9 Mmcf per day, 7,480 psi on 30/64ths choke on May 2, 2009.

We participated in one non-operated well in northern DeSoto Parish, Louisiana that IP’d at 13.8 Mmcf per day and one well in Caddo Parish, Louisiana that IP’d at 10.0 Mmcf per day. We also have three other non-operated wells, two in DeSoto Parish, Louisiana and one in Caddo Parish, Louisiana, that are in the completion phase.

Our DeSoto Parish area has yielded some of the highest production rates in the entire play. The EXCO operated average IP in DeSoto Parish is 24 Mmcf per day, with all five of our wells having IPs in excess of 21 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. Our initial wells were completed with 9-10 frac stages and our most recent wells have been completed with 11-12 frac stages to maximize reserves and production and provide more contact with the fractured shale reservoir. Our completion design and strategy has not changed, as we continue to utilize intermediate strength proppants in all of our operated completions.

Our drilling times are improving and considerable operational efficiencies have been made. Our initial wells were 70 - 75 days from spud to rig release and two of our recent wells have been 45 - 50 days. These improvements have been realized through a variety of factors including less directional drilling in the intermediate hole section, rig efficiencies, improvements in the mud systems and bit selection. Our lateral lengths are now typically 4,500 feet and are designed to maximize length in the target interval. Our completion operations are initiated immediately following rig release, and our pipeline construction runs parallel to our drilling operations. All of our operated wells have flowed to sales immediately following completion operations due to close coordination with our midstream business. Our midstream activity is progressing as planned with construction of a 36-inch pipeline header system and associated treating facilities. The 36-inch header system is designed to flow both EXCO and third party gas. We have firm transportation of 370 Mmcf per day in the immediate area, including our new commitments on a recently announced third party pipeline project scheduled to be completed in late 2009. EXCO is positioned extremely well in the play and has considerable growth potential with over 4.5 Tcf of potential Haynesville shale reserves.

Cotton Valley

In the first quarter 2009, we drilled 13 gross (11.9 net) Cotton Valley wells. Of the 13 gross wells, 4 gross (3.6 net) were in our Vernon field, 4 gross (4.0 net) were in Danville and 5 gross (4.3 net) were in the Holly field area. With current natural gas prices at the lowest levels in several years, we have elected to suspend further operated Cotton Valley drilling.

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. As a result of low commodity prices, conventional drilling activities have been minimal during the quarter. During the first quarter 2009, we achieved a 100% drilling success rate on the 2 gross (2.0 net) wells drilled on our Appalachian properties. At the end of the quarter we had no active drilling rigs in the region.

In Appalachia, we hold in excess of 1,028,000 net leasehold acres. Included as a subset of this acreage position, we now control approximately 361,000 net acres in the Marcellus shale fairway, with in excess of 215,000 net acres located in the core area of the overpressured Marcellus. A significant percentage of this fairway acreage is held by production (HBP) by our shallow producing assets. Also as a subset of our acreage position, 130,000 net acres (70% HBP) exist within the Huron Shale play of West Virginia. We believe our present leasehold position in the Marcellus and Huron Shale fairways contains between 7 – 12 Tcf of potential reserves.

In 2008, we drilled 6 vertical and 4 horizontal wells. During the first quarter 2009 much of our technical Marcellus activity was focused on integrating our 2008 Marcellus well results and seismic data to high grade for a 2009 and 2010 development program and to continue delineating our remaining acreage blocks using our updated geological model. We have made substantial progress on our permitting efforts. The remainder of 2009 will be focused on further planning and executing our drilling program in the Marcellus.

Other

We drilled and completed 7 gross (6.3 net) wells and drilled 2 dry holes in our Permian area Canyon Sand field during the first quarter 2009 resulting in a 78% success rate. Two of these wells were drilled to earn 11,000 net contiguous acres under a joint venture. No drilling was underway in our Permian area at the end of the first quarter 2009. We are evaluating recently acquired 3-D seismic over approximately 35,000 net acres adjacent to our Canyon Sand field. Our total leasehold in this area is approximately 77,000 net acres.

Our Mid-Continent division production averaged approximately 64 Mmcfe per day during the first quarter 2009. In the Mid-Continent, we drilled and completed 4 gross (2.8 net) wells during the first quarter 2009. At current commodity prices, we have suspended operated drilling in this region.

Midstream

Throughput on our transportation and gathering systems in East Texas and North Louisiana averaged 580 Mmcf per day for the first quarter 2009, up from 554 Mmcf per day in the fourth quarter 2008. In 2009, we are focused on the installation of our 29 mile Haynesville Header system, which will be strategically located near our Haynesville shale development in northwest Louisiana. Some phases of the project are expected to be operational in the third quarter 2009. When complete, the system will have throughput capacity of 500 Mmcf per day at 500 psi, expandable to 1.2 Bcf per day with operational changes in line pressure and compression. This pipeline installation program will ensure that EXCO and other third party producers have access to multiple gas markets.

Financial Data

Our consolidated balance sheets as of March 31, 2009 and December 31, 2008, consolidated statements of operations for the three months ended March 31, 2009 and 2008 and consolidated statements of cash flows for the three months ended March 31, 2009 and 2008 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 6, 2009 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# 95952874. 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, May 5, 2009, 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 20, 2009. Please call (800) 642-1687 and enter conference ID# 95952874 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.

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, 2008 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 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, 2008 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 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 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 $5.8 million for the three months ended March 31, 2009 for interest rate swaps included in GAAP interest expense.