EXCO Resources, Inc. Reports Record Operating and Financial Results for the First Quarter 2008

EXCO Resources, Inc. (NYSE: XCO) today announced first quarter results for 2008. Adjusted net earnings available to common shareholders, a non-GAAP measure adjusting for non-cash derivative losses and items typically not included by securities analysts in published estimates, were $0.28 per share for the first quarter 2008 compared with $0.07 per share for the first quarter 2007. Oil and natural gas revenues for the quarter were $318 million, exclusive of derivative financial instrument activities (derivatives) and $321 million inclusive of cash settlements on derivatives. Oil and natural gas revenues for the prior year’s quarter were $118 million before derivatives, and $151 million including cash settlements on derivatives. Oil and natural gas production for the quarter set a record at 35 Bcfe, or 386 Mmcfe per day comprised of 352 Mmcf per day of natural gas and 5,575 barrels per day of oil, which was more than 100% higher than the first quarter 2007 production of 17 Bcfe, or 192 Mmcfe per day, and approximately 2% higher than the fourth quarter 2007 production of 377 Mmcfe per day. Presently our daily average production exceeds 400 Mmcfe per day. Adjusted earnings before interest, taxes, depreciation, depletion and amortization and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the quarter were $254 million, approximately 2.2 times the prior year’s quarter. Direct operating expenses for the quarter were $0.95 per Mcfe compared with $1.25 per Mcfe in the prior year’s quarter, a reduction of 24%, and slightly lower than the fourth quarter 2007 direct operating expense rate of $0.97 per Mcfe. Production and ad valorem taxes for the first quarter 2008 were 6.1% of oil and natural gas revenues before derivatives ($0.55 per Mcfe) compared with 7.1% during the first quarter 2007 ($0.48 per Mcfe). Drilling and development capital expenditures for the quarter totaled a record $152 million compared with first quarter 2007 capital expenditures of $76 million. Total capital expenditures for the first quarter 2008, which includes leasing, midstream projects and corporate expenditures, were $184 million, an increase of 111% from the prior year’s quarter. Douglas H. Miller, EXCO’s Chief Executive Officer commented, "Obviously, we are pleased with our first quarter accomplishments, which included records in production, adjusted EBITDA and capital spending. We have several very positive trends taking place at EXCO including our growing focus on the Marcellus and Huron shales in Appalachia and the Haynesville shale in East Texas and North Louisiana. In addition, we continue to have outstanding development drilling results in the Vernon and Holly/Caspiana Fields in Louisiana and in our Sugg Ranch area in the Permian Basin. We have successfully reduced the number of days from spud to rig release by 30% in some areas, and production volumes and the number of drilling locations in the Vernon Field are significantly more than we thought they would be a year ago. These development activities are providing substantial cash flows to help fund our expected increased drilling in the shales in the coming quarters.” Revenues and adjusted revenues Our first quarter 2008 adjusted revenues, a non-GAAP measure defined as revenues which exclude the non-cash impact of our oil and natural gas derivatives, were $329 million, an increase of $172 million, or 109% from the first quarter 2007. The increase was primarily attributable to our higher production volumes reflecting acquisitions closed during 2007. Realized prices, after cash settlements on derivatives, were $9.14 per Mcfe and $8.70 per Mcfe for the three months ended March 31, 2008 and 2007, respectively.         Three months ended March 31, % change over quarter ended (in thousands, except prices) 2007   2008 March 31, 2007 Oil and natural gas revenues, before derivative financial instruments $ 118,495 $ 317,690 168 % Cash settlements on derivative financial instruments   32,073     3,015   Subtotal, revenues including cash settlements on derivative financial instruments 150,568 320,705 Non-cash loss on oil and natural gas derivative financial instruments   (128,092 )   (344,209 ) 169 % Oil and natural gas revenues 22,476 (23,504 ) -205 % Pipeline and marketing 5,345 7,427 39 % Interest and other   1,380     1,118   -19 % Total revenues, marketing and other income, GAAP 29,201 (14,959 ) -151 % Elimination of non-cash oil and natural gas derivative financial instrument activity included in GAAP revenues   128,092     344,209   Adjusted revenues (1) $ 157,293   $ 329,250   109 %   Prices, excluding marketing and other income: Realized price per Mcfe, before derivative financial instruments $ 6.84 $ 9.05 32 % Realized price per Mcfe, after cash settlements on derivative financial instruments $ 8.70 $ 9.14 5 % (1) EXCO does not designate its derivatives as hedges. As a result, unrealized gains or losses in the fair market value of our derivatives are recognized as a component of current revenues. Adjusted revenues are not a measure of revenues in accordance with GAAP. Management believes that adjusted revenues are a meaningful measure to investors and rating agencies as they present the combination of actual revenues before the impact of oil and natural gas derivatives in accordance with GAAP, combined with the actual cash receipts or settlements arising from the oil and natural gas derivative program. Adjusted revenues specifically exclude the non-cash unrealized gains or losses from derivative activities as the non-cash impact of the changes in the fair value of derivatives does not impact our current liquidity and cash flows used to fund our operations, execute our capital program and make acquisitions. Cash Flow Our cash flow from operations before working capital changes and adjustments for settlements of derivative financial instruments with a financing element for the current quarter was $222 million, or a 364% increase from 2007. We utilized this cash flow primarily to fund $184 million of capital expenditures (exclusive of acquisitions).         Three months ended March 31, % change over quarter ended (in thousands) 2007   2008 March 31, 2007 Cash flow from operations, GAAP $ 32,551 $ 199,510 Net change in working capital 15,339 12,085 Settlements of derivative financial instruments with a financing element - 10,467         Cash flow from operations before changes in working capital, non-GAAP measure (1) $ 47,890 $ 222,062 364 % (1) Cash flow from operations before working capital changes and adjustments for settlements of derivative financial instruments with a financing element is presented because management believes it is a useful financial indicator for companies in our industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company’s ability to provide cash used to fund development and acquisition activities and service debt or pay dividends. Operating cash flow is not a measure of financial performance pursuant to GAAP and should not be used as an alternative to cash flows from operating, investing, or financing activities. We have also elected to exclude the adjustment for derivative financial instruments with a financing element as this adjustment simply reclassifies settlements from operating cash flows to financing activities. Management believes these settlements should be included in this non-GAAP measure to conform with the intended measure of our ability to provide cash to fund operations and development activities. Net Income Our reported net 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 and certain items management believes affect the comparability of our results of operations which are included in GAAP net income measures. The following table provides a reconciliation of our net loss and net loss available to common shareholders to non-GAAP measures of adjusted net income and adjusted net income available to common shareholders:   Three months ended   Three months ended March 31, 2007 March 31, 2008 (in thousands, except per share amounts) Amount   Per share Amount   Per share Net loss, GAAP $ (87,697 ) $ (162,839 ) Adjustments: Non-cash mark-to-market losses on oil and natural gas derivative financial instruments, before taxes 128,092 344,209   Non-cash mark-to-market losses on interest rate derivative financial instruments, before taxes - 3,631 Nonrecurring financing costs, before taxes (1) 32,100 - Income taxes on adjustments   (64,109 )   (120,316 ) Total adjustments, net of taxes   96,083     227,524   Adjusted net income $ 8,386   $ 64,685     Net loss available to common shareholders, GAAP (2) $ (88,833 ) $ (0.85 ) $ (197,839 ) $ (1.89 ) Impact of potentially dilutive common stock equivalents (3) 0.02 0.03 Adjustments shown above (4)   96,083     0.90     227,524     2.14   Adjusted net income available to common shareholders (4) $ 7,250   $ 0.07   $ 29,685   $ 0.28   (1) See "Consolidated statement of operations” for a detailed explanation. (2) Per share amount is based on weighted average number of common shares outstanding of 104,201,768 and 104,682,724 for the three months ended March 31, 2007 and 2008, respectively. (3) Potentially dilutive common stock equivalents were 2,245,500 and 1,791,867 for the three months ended March 31, 2007 and 2008, respectively. For the computation of adjusted net income per share, these common stock equivalents have been included to reflect the impact of the adjustments which result in income as opposed to a loss. (4) Computed using diluted shares of 106,447,268 and 106,474,591 for the three months ended March 31, 2007 and 2008, respectively. Development and Exploitation Activity We spent $152 million on development and exploitation activities, drilling and completing 90 gross wells in the first quarter 2008. Our overall drilling success rate during the first quarter 2008 was 97%. Our total capital expenditures, including our leasing, midstream and corporate activities, were $184 million. In 2008, our approved capital budget is approximately $800 million and we plan to drill approximately 700 gross wells. Our plans for the remainder of 2008 include exploiting the Marcellus, Huron and Haynesville shales and development drilling in all of our operating areas. The concentration during 2008 will be in the following areas: East Texas/North Louisiana Our primary targets across this area have been the upper and lower Cotton Valley, the Travis Peak, Pettet, and Hosston formations. We are increasing emphasis on our significant position of more than 100,000 net acres in the emerging Haynesville shale play, where we have begun drilling evaluation wells to test and delineate the Haynesville. Our initial Haynesville shale results are very encouraging and we plan to add a drilling rig for horizontal development of the Haynesville in this area by mid-year 2008. A substantial percentage of our acreage in the Haynesville shale play is held by production. We believe our Haynesville acreage could hold at least 2-5 Tcfe of potential reserves. Following excellent drilling results in certain areas, particularly including Holly/Caspiana, Vernon and some newly leased acreage in East Texas, as well as opportunities to lease additional acreage and drill in the emerging Haynesville shale, we plan to increase our capital program in this area. We will seek additional funding approval from our Board of Directors and add to the existing budget, which now totals approximately $338 million for this area. In our Shreveport operating area, we have increased net production from 71.6 Mmcfe per day when we took over operations in October 2006 to the current production level of 86.8 Mmcfe per day. We have expanded the Holly/Caspiana Field limits through our drilling. In one area of East Texas, we have drilled a well on a recently leased Cotton Valley prospect, and the well had an initial daily gross production rate of 430 barrels of oil and 1.0 Mmcf of natural gas. We are evaluating this new area for additional opportunities. The Vernon Field net production is currently 130 Mmcfe per day, which represents eight months of stable production. Our drilling and exploitation efforts have reduced the overall field decline from that forecast at the time of acquisition and have expanded the field limits in the southern and western fault blocks. We now have approximately 280 drilling locations at Vernon, up significantly from the 15 identified at the time of acquisition. A recent completion had an initial production rate of 10.3 Mmcfe per day, our highest initial production rate from a new well since the acquisition. Vernon also continues to provide significant cash flow which is funding capital activity across our portfolio. Our Midstream operations in East Texas/North Louisiana continue to grow from both third party and company-owned production throughput. Current throughput is approximately 535 Mmcf per day, with approximately 60% of the volumes from equity production and approximately 40% from third parties. The 535 Mmcf per day throughput is up from 460 Mmcf per day at year end 2007, with the increase attributable to both the first quarter 2008 acquisition of a 230 mile gathering system in East Texas and new third party volumes. 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 Upper Devonian sandstones, Devonian shale, and Berea shale, among other productive horizons. We are continuing our efforts to apply artificial lift technology in the basin, with promising initial results. Our major focus in Appalachia during the first quarter 2008 has been positioning ourselves for exploitation of our significant Marcellus and Huron shale holdings. We hold more than 382,000 net acres in the Marcellus shale area (most of which is held by shallow production), with more than 243,000 net acres within the overpressured fairway in Pennsylvania. During April 2008, we negotiated commitments for an additional 33,000 net Marcellus acres which will increase our total Marcellus acreage holdings to approximately 415,000 net acres. We hold more than 121,000 net acres in the Huron shale area of West Virginia, also mostly held by shallow production. To begin exploiting our shale opportunities, our Board of Directors approved an increase to our 2008 capital budget in Appalachia from the originally approved $69 million to $244 million. We spud our first horizontal well in the Marcellus play during April and plan to drill a total of four horizontals and more than seven vertical wells during 2008. In the Huron shale area, we plan to drill four horizontal wells this year. We believe our combined Marcellus and Huron shale reserve potential totals at least 7-12 Tcfe. Other Our Permian Canyon Sand field development and extension work is continuing. Production from the field has increased from approximately 19.7 Mmcfe per day of natural gas at November 1, 2007 to more than 24 Mmcfe per day today. We plan to drill 124 wells in the field during 2008. Of the $110 million budgeted for the Permian Area in 2008, approximately $80 million is allocated for drilling and completion in the Canyon Sand field. In the first quarter 2008 we negotiated a joint venture including approximately 11,000 contiguous net acres adjacent to this field, are now acquiring seismic data over the area, and will drill in this area later this year. We are budgeting $48 million of capital for the Mid-Continent area and $11 million for the Rockies. Acquisitions On February 20, 2008, we acquired shallow natural gas properties located primarily in our central Pennsylvania operating area. The properties included approximately 2,500 producing wells, approximately 2,000 shallow undrilled locations and 16 Mmcfe per day of net production. The purchase price was $388 million after reductions for preliminary closing adjustments. The acquisition was financed with our revolving bank credit facility. We also closed an acquisition of a privately held gathering system in East Texas in March 2008 for $56 million, net of preliminary closing adjustments. Liquidity On February 20, 2008, our combined borrowing base on our revolving credit facilities was increased to approximately $2.5 billion. As of May 1, 2008, our unused borrowing capacity was $365.2 million. Financial Data Our condensed consolidated balance sheets as of December 31, 2007 and March 31, 2008, condensed consolidated statements of operations for the three months March 31, 2007 and 2008, and condensed consolidated statements of cash flows for the three months ended March 31, 2007 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 7, 2008 at 1:00 p.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call (800) 309-5788 if you wish to participate, and ask for the EXCO conference call ID# 45480181. 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 6, 2008, after market close. A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., May 14, 2008. Please call (800) 642-1687 and enter conference ID# 45480181 to hear the recording. A digital recording of the conference call will also be available on EXCO’s website. Additional information about EXCO Resources, Inc. may be obtained by contacting EXCO’s Chairman, Douglas H. Miller, or its President, Stephen F. Smith, at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting EXCO’s website at http://www.excoresources.com. EXCO’s SEC filings and press releases can be found under the Investor Relations tab. We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this presentation, and the risk factors included in the Annual Report on Form 10-K for the year ended December 31, 2007 and our other periodic filings with the SEC. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. The SEC has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms "probable,” "possible,” "potential,” "unproved,” or "unbooked potential,” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2007 available on our website at www.excoresources.com under the Investor Relations tab or by calling us at 214-368-2084.   EXCO Resources, Inc. Condensed consolidated balance sheets       December 31, March 31, (in thousands) 2007 2008 Assets Current assets: Cash and cash equivalents $ 55,510 $ 9,113 Accounts receivable: Oil and natural gas 146,297 180,029 Joint interest 21,614 22,871 Interest and other 2,151 5,296 Derivative financial instruments 66,632 - Deferred income taxes 6,764 - Other   12,332     11,671   Total current assets   311,300     228,980   Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties 334,803 372,066 Proved developed and undeveloped oil and natural gas properties 4,926,053 5,447,621 Accumulated depletion   (500,493 )   (604,406 ) Oil and natural gas properties, net   4,760,363     5,215,281   Gas gathering assets 340,706 428,057 Accumulated depreciation and amortization   (16,142 )   (19,614 ) Gas gathering assets, net   324,564     408,443   Office and field equipment, net 20,844 21,800 Advance on pending acquisition 39,500 3,500 Derivative financial instruments 2,491 4,561 Deferred financing costs, net 20,406 19,949 Other assets 6,226 3,422 Goodwill   470,077     470,077   Total assets $ 5,955,771   $ 6,376,013     EXCO Resources, Inc. Condensed consolidated balance sheets     December 31, March 31, (in thousands, except per share and share data)   2007   2008   Liabilities and shareholders' equity Current liabilities: Accounts payable and accrued liabilities $ 106,305 $ 111,851 Accrued interest payable 21,835 15,563 Revenues and royalties payable 100,978 120,120 Income taxes payable 87 87 Deferred income taxes - 66,617 Current portion of asset retirement obligations 1,656 1,850 Derivative financial instruments   47,306   268,781   Total current liabilities   278,167   584,869   Long-term debt 2,099,171 2,479,048 Asset retirement obligations and other long-term liabilities 89,810 102,514 Deferred income taxes 271,398 121,105 Derivative financial instruments 109,205 171,008 Commitments and contingencies - -   7.0% Cumulative Convertible Perpetual Preferred Stock, par value $0.001 per share, 39,008 shares outstanding at December 31, 2007 and March 31, 2008, liquidation preference of $391,218 at December 31, 2007 and March 31, 2008, respectively 388,574 388,574   Hybrid Preferred Stock, par value $0.001 per share, 160,992 shares outstanding at December 31, 2007 and March 31, 2008, respectively, liquidation preference of $1,614,616 at December 31, 2007 and March 31, 2008, respectively 1,603,704 1,603,704 Shareholders' equity: Preferred stock, par value $0.001 per share; 10,000,000 shares authorized at March 31, 2008, of which 200,000 shares have been designated for each series of 7.0% Cumulative Convertible Perpetual Preferred Stock and 200,000 shares have been designated for each series of Hybrid Preferred Stock; no shares of preferred stock other than the 7.0% Cumulative Convertible Perpetual and Hybrid Preferred Stock (presented above) are issued and outstanding at March 31, 2008 - - Common stock, $0.001 par value; Authorized shares - 350,000,000; issued and outstanding shares - 104,578,941 at December 31, 2007 and 104,887,915 at March 31, 2008 105 105 Additional paid-in capital 1,043,645 1,050,933 Retained earnings (deficit)   71,992   (125,847 ) Total shareholders' equity   1,115,742   925,191   Total liabilities and shareholders' equity $ 5,955,771 $ 6,376,013     EXCO Resources, Inc. Condensed consolidated statement of operations   Three months ended March 31, (in thousands, except per share data) 2007   2008 Revenues and other income: Oil and natural gas $ 118,495 $ 317,690 Loss on derivative financial instruments (96,019 ) (341,194 ) Pipeline and marketing 5,345 7,427 Interest and other   1,380     1,118   Total revenues and other income   29,201     (14,959 ) Costs and expenses: Oil and natural gas production 30,078 52,481 Gathering and transportation 821 3,131 Depreciation, depletion and amortization 51,324 109,217 Accretion of discount on asset retirement obligations 943 1,316 General and administrative 14,175 22,627 Interest (1)   76,709     36,020   Total costs and expenses   174,050     224,792   Loss before income taxes (144,849 ) (239,751 ) Income tax benefit   (57,152 )   (76,912 ) Net loss (87,697 ) (162,839 ) Preferred stock dividends   1,136     35,000   Net loss available to common shareholders $ (88,833 ) $ (197,839 ) Net loss per common share: Net loss per common share - basic $ (0.85 ) $ (1.89 ) Net loss per common share - diluted $ (0.85 ) $ (1.89 ) Weighted average shares: Basic   104,202     104,683   Diluted   104,202     104,683   (1)Interest expense for the three months ended March 31, 2007 includes one time charges of $32.1 million incurred during the first quarter 2007. Expenses associated with the payoff of the EXCO Partners Operating Partnership Senior Term Credit Agreement included a $13.0 million redemption premium, a $9.2 million write-off of deferred financing costs, and a $3.0 million write-off of unamortized original issue discount. In addition, $6.9 million of commitment fees were expensed in connection with other debt arrangements that were terminated. Interest expense for the three months ended March 31, 2008 includes an increase of $3.6 million as a result of non-cash losses resulting from interest rate swaps entered into during the first quarter 2008.   EXCO Resources, Inc. Consolidated statement of cash flows   Three months ended March 31, (in thousands) 2007   2008 Operating Activities: Net loss $ (87,697 ) $ (162,839 ) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 51,324 109,217 Stock option compensation expense 1,910 3,004 Accretion of discount on asset retirement obligations 943 1,316 Non-cash change in fair value of derivatives 128,092 347,839 Cash settlements of assumed derivatives - (10,467 ) Deferred income taxes (56,037 ) (76,912 ) Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011 and discount on long-term debt 9,355 406 Loss on sale of fixed assets - 31 Effect of changes in: Accounts receivable 8,494 (38,133 ) Other current assets 361 2,389 Accounts payable and other current liabilities   (24,194 )   23,659   Net cash provided by operating activities   32,551     199,510   Investing Activities: Additions to oil and natural gas properties, gathering systems and equipment (1,489,950 ) (602,667 ) Advance on pending acquisition (43,000 ) (3,500 ) Proceeds from disposition of property and equipment and other   131,594     1,298   Net cash used in investing activities   (1,401,356 )   (604,869 ) Financing Activities: Borrowings under credit agreements 1,198,000 500,700 Repayments under credit agreements (1,672,532 ) (120,000 ) Proceeds from issuance of common stock 817 3,527 Proceeds from issuance of preferred stock 2,000,000 - Payment of preferred stock dividends - (35,000 ) Payments for preferred stock issuance costs (525 ) - Settlements of derivative financial instruments with a financing element - 10,467 Deferred financing costs   (10,099 )   (732 ) Net cash provided by financing activities   1,515,661     358,962   Net increase (decrease) in cash 146,856 (46,397 ) Cash at beginning of period   22,822     55,510   Cash at end of period $ 169,678   $ 9,113     Supplemental Cash Flow Information: Interest paid $ 92,695   $ 38,627   Derivative financial instruments assumed in Vernon Acquisition $ 60,015   $ -   Supplemental non-cash investing and financing activities: Capitalized stock compensation $ 368   $ 675   Issuance of common stock for director services $ -   $ 82     EXCO Resources, Inc. Consolidated EBITDA And adjusted EBITDA reconciliations and statement of cash flow data (Unaudited)   Three months ended March 31,   March 31, (in thousands) 2007 2008   Net loss $ (87,697 ) $ (162,839 ) Interest expense 76,709 36,020 Income tax benefit (57,152 ) (76,912 ) Depreciation, depletion and amortization   51,324       109,217   EBITDA(1) (16,816 ) (94,514 ) Accretion of discount on asset retirement obligations 943 1,316 Non-cash change in fair value of oil and natural gas derivative financial instruments 128,092 344,209 Stock based compensation expense   1,910     3,004   Adjusted EBITDA(1) $ 114,129   $ 254,015   Interest expense (2) (76,709 ) (32,390 ) Income tax benefit 57,152 76,912   Amortization of deferred financing costs, premium on 7 1/4% senior notes due 2011 and discount on long-term debt 9,355 406 Loss on sale of assets - 31 Deferred income taxes (56,037 ) (76,912 ) Changes in operating assets and liabilities (15,339 ) (12,085 )   Settlements of derivative financial instruments with a financing element   -     (10,467 ) Net cash provided by operating activities $ 32,551   $ 199,510         Three months ended March 31, March 31, (in thousands) 2007 2008   Statement of cash flow data: Cash flow provided by (used in): Operating activities(2) $ 32,551 $ 199,510 Investing activities (1,401,356 ) (604,869 ) Financing activities 1,515,661 358,962 Other financial and operating data: EBITDA(1) (16,816 ) (94,514 ) Adjusted EBITDA(1) 114,129 254,015 (1) Earnings before interest, taxes, depreciation, depletion and amortization, or "EBITDA” represents net income adjusted to exclude interest expense, income taxes, depreciation, depletion and amortization. "Adjusted EBITDA” represents EBITDA adjusted to exclude accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives and stock-based compensation. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, these measures are used in covenant calculations required under our credit agreements and the indenture governing our 7 1/4 % senior notes. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to us. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures. (2) Excludes non-cash change in fair value of interest rate swaps included in GAAP interest expense.   EXCO Resources, Inc. Summary of operating data     Three months ended March 31,   March 31, %   2007 2008 Change   Production: Oil (Mbbls) 275 507 84 % Gas (Mmcf) 15,663 32,049 105 % Oil and natural gas (Mmcfe) 17,313 35,091 103 %   Average sales prices (before derivative financial instrument activities): Oil (per Bbl) $ 54.93 $ 96.68 76 % Gas (per Mcf) 6.60 8.38 27 % Total production (per Mcfe) 6.84 9.05 32 %   Average costs (per Mcfe): Oil and natural gas operating costs $ 1.25 $ 0.95 -24 % Gathering and transportation costs 0.05 $ 0.09 80 % Production and ad valorem taxes 0.48 0.55 15 % General and administrative 0.82 0.64 -22 % Depletion 2.80 2.96 6 % Depreciation and amortization 0.17 0.15 -12 %