PRESS RELEASE

Original Article

DALLAS, May 04, 2010 (BUSINESS WIRE) — EXCO Resources, Inc. (XCO 17.20, -0.82, -4.55%) 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:

                                           Three months ended March 31,
                                ---------------------------------------------------
                                   2010                      2009                    Quarter to quarter change
                                ----------  --------------------------------------- --------------------------
                                                                                      Versus       Versus
                                  Actual      Actual       Pro forma     Pro forma    actual      pro forma
(in Mmcfe)                      production  production  adjustment (1)  production  production   production
------------------------------  ----------  ----------  --------------- ----------  ---------- ---------------
Producing region:
    East Texas/North Louisiana      18,753      22,616   (7,246 )           15,370   (3,863 )  3,383
    Appalachia                       3,341       5,125   (1,476 )            3,649   (1,784 )   (308 )
    Permian and other                1,697       2,853     (500 )            2,353   (1,156 )   (656 )
    Mid-Continent                        -       5,752   (5,752 )                -   (5,752 )      -
                                ----------  ----------  ------- ------  ----------  ------- -  -----
        Total                       23,791      36,346  (14,974 )           21,372  (12,555 )  2,419
                                ==========  ==========  ======= ======  ==========  ======= =  =====
(
1) The pro forma adjustments reduce production volumes
attributable to properties sold in 2009 and properties affected by
the BG Upstream Transaction as if these sales had occurred on
January 1, 2009.

– 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:

                                                                        Three months ended              Three months ended
                                                                          March 31, 2010                  March 31, 2009
                                                                   ----------------------------- --------------------------------
(in thousands, except per share amounts)                               Amount        Per share        Amount          Per share
-----------------------------------------------------------------  -------------- -------------- ----------------- --------------
Net income (loss), GAAP                                             $ 115,568                     $ (1,099,611 )
Adjustments:
N                                                                     (24,120 )                       (128,741 )
on-cash mark-to-market gains on derivative financial instruments,
before taxes
Non-cash write down of oil and natural gas properties                       -                        1,293,579
Income taxes on above adjustments (1)                                   9,648                         (465,935 )
Adjustment to deferred tax asset valuation allowance (2)              (46,227 )                        440,478
                                                                      ------- --                    ----------
    Total adjustments, net of taxes                                   (60,699 )                      1,139,381
                                                                      ------- --                    ----------
Adjusted net income                                                 $  54,869                     $     39,770
                                                                   == =======                    == ==========
Net income (loss), GAAP (3)                                         $ 115,568       $  0.54       $ (1,099,611 )     $ (5.21 )
Adjustments shown above (3)                                           (60,699 )       (0.29 )        1,139,381          5.40
                                                                      ------- --      ----- ---     ----------         -----
Adjusted net income for diluted earnings per share                  $  54,869       $  0.25       $     39,770       $  0.19
                                                                   == =======     === =====      == ==========     === =====
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding                            212,086                          210,995
Dilutive stock options                                                  3,580                                -
                                                                      -------                       ----------
Shares used to compute diluted EPS for adjusted net income            215,666                          210,995
                                                                      =======                       ==========

(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.

                                                                      Three months ended
                                                                           March 31,               %
                                                                 -----------------------------
(in thousands)                                                         2010           2009      change
---------------------------------------------------------------  ---------------- ------------ --------
Cash flow from operations, GAAP                                    $  91,303        $ 105,326
Net change in working capital                                         45,389           22,186
S                                                                       (907 )         37,616
ettlements of derivative financial instruments with a financing
element
                                                                     ------- ---      -------
C                                                                  $ 135,785        $ 165,128  -18 %
ash flow from operations before changes in working capital,
non-GAAP measure (1)
                                                                 === ======= ===  === =======  === ===

(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:

                                                 April - December
                                     Q1 2010       2010 capital      Total 2010
(in millions)                        actuals          budget       capital budget
------------------------------   --------------- ----------------- ---------------
East Texas/North Louisiana          $   68           $   187          $  255
Appalachia                              42               112             154
Permian and other                        8                21              29
Corporate                               12                13              25
                                      ----             -----            ----
    Total capital expenditures         130               333             463
TGGT equity contributions               45                30              75
Property acquisitions                    9                 -               9
Sales of property (1)                  (67 )             (69 )          (136 )
                                      ---- ----        ----- ----       ---- ----
Total investing activities          $  117           $   294          $  411
                                 ==== ====       ===== =====       ==== ====
(
1) Consist primarily of reimbursements from BG Group pursuant to
the BG AMI

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.

                                                       E
                                              XCO Resources, Inc.
                                          Consolidated balance sheet
                                                                          March 31,          December 31,
(in thousands)                                                              2010                 2009
-------------------------------------------------------------------  ------------------- ---------------------
                                                                         (Unaudited)
Assets
Current assets:
    Cash and cash equivalents                                          $     47,804         $     68,407
    Restricted cash                                                          69,988               58,909
    Accounts receivable, net:
        Oil and natural gas                                                  67,984               56,485
        Joint interest                                                       76,408               47,104
        Interest and other                                                   53,099               10,832
    Inventory                                                                14,580               15,830
    Derivative financial instruments                                        142,474              138,120
    Other                                                                     7,869                6,401
                                                                         ----------           ----------
            Total current assets                                            480,206              402,088
                                                                         ----------           ----------
Equity investment in TGGT Holdings, LLC                                     261,576              216,987
Oil and natural gas properties (full cost accounting method):
    Unproved oil and natural gas properties                                 381,961              492,882
    Proved developed and undeveloped oil and natural gas properties       1,989,923            1,875,749
    Accumulated depletion                                                (1,166,623 )         (1,132,604 )
                                                                         ---------- ---       ---------- ----
    Oil and natural gas properties, net                                   1,205,261            1,236,027
                                                                         ----------           ----------
Gas gathering assets                                                        182,633              180,506
    Accumulated depreciation and amortization                               (25,023 )            (22,841 )
                                                                         ---------- ---       ---------- ----
    Gas gathering assets, net                                               157,610              157,665
                                                                         ----------           ----------
Office and field equipment, net                                              30,381               31,771
Deferred financing costs, net                                                 6,758                7,602
Derivative financial instruments                                             45,767               34,677
Goodwill                                                                    269,656              269,656
Other assets                                                                 10,384                2,421
                                                                         ----------           ----------
            Total assets                                               $  2,467,599         $  2,358,894
                                                                     === ==========      ==== ==========

                                                     E
                                            XCO Resources, Inc.
                                        Consolidated balance sheet
(in thousands, except per share and share data)                              2010               2009
--------------------------------------------------------------------  ------------------- -----------------
                                                                          (Unaudited)
Liabilities and shareholders' equity
Current liabilities:
  Accounts payable and accrued liabilities                              $     89,254       $    112,991
  Revenues and royalties payable                                              95,552             79,356
  Accrued interest payable                                                     8,010             16,193
  Current portion of asset retirement obligations                                900                900
  Income taxes payable                                                           210                210
  Derivative financial instruments                                               368              3,264
  Current maturities of long term debt                                       447,779                  -
                                                                          ----------         ----------
    Total current liabilities                                                642,073            212,914
                                                                          ----------         ----------
Long-term debt, net of current maturities                                    762,543          1,196,277
Deferred income taxes                                                              -                  -
Derivative financial instruments                                               5,908             11,688
Asset retirement obligations and other long-term liabilities                  78,354             78,427
Commitments and contingencies                                                      -                  -
Shareholders' equity:
                                                                                   -                  -
  Preferred stock, $0.001 par value; authorized shares - 10,000,000;
  none issued and outstanding
                                                                                 212                212
  Common stock, $0.001 par value; authorized shares - 350,000,000;
  issued and outstanding shares - 212,238,537 at March 31, 2010 and
  211,905,509 at December 31, 2009
  Additional paid-in capital                                               3,115,167          3,105,238
  Accumulated deficit                                                     (2,136,658 )       (2,245,862 )
                                                                          ---------- ---     ---------- --
    Total shareholders' equity                                               978,721            859,588
                                                                          ----------         ----------
    Total liabilities and shareholders' equity                          $  2,467,599       $  2,358,894
                                                                      === ==========      == ==========

                                                       E
                                              XCO Resources, Inc.
                                     Consolidated statement of operations
                                                  (Unaudited)
                                                                                 Three months ended
                                                                                      March 31,
                                                                      ----------------------------------------
(in thousands, except per share data)                                        2010                2009
--------------------------------------------------------------------  ------------------ ---------------------
Revenues:
  Oil and natural gas                                                    $ 130,994          $    172,208
  Midstream                                                                      -                17,013
                                                                           -------            ----------
    Total revenues                                                         130,994               189,221
                                                                           -------            ----------
Costs and expenses:
  Oil and natural gas production                                            27,058                53,118
  Midstream operating                                                            -                18,450
  Gathering and transportation                                              11,113                 3,897
  Depreciation, depletion and amortization                                  38,818                81,794
  Write-down of oil and natural gas properties                                   -             1,293,579
  Accretion of discount on asset retirement obligations                      1,089                 2,071
  General and administrative                                                26,419                20,547
  Other operating items                                                       (407 )                (405 )
                                                                           ------- ----       ---------- ----
    Total costs and expenses                                               104,090             1,473,051
                                                                           -------            ----------
  Operating income (loss)                                                   26,904            (1,283,830 )
Other income (expense):
  Interest expense                                                         (10,634 )             (36,132 )
  Gain on derivative financial instruments                                  99,149               221,384
  Other income                                                                  60                    22
  Equity method income in TGGT Holdings, LLC                                    89                     -
                                                                           -------            ----------
    Total other income                                                      88,664               185,274
                                                                           -------            ----------
Income (loss) before income taxes                                          115,568            (1,098,556 )
Income tax expense                                                               -                 1,055
                                                                           -------            ----------
Net income (loss)                                                        $ 115,568          $ (1,099,611 )
                                                                      ==== =======       ==== ========== ====
Earnings (loss) per common share:
  Basic
    Net income (loss)                                                    $    0.54          $      (5.21 )
                                                                      ==== =======       ==== ========== ====
    Weighted average number of common shares outstanding                   212,086               210,995
                                                                           =======            ==========
  Diluted
    Net income (loss)                                                    $    0.54          $      (5.21 )
                                                                      ==== =======       ==== ========== ====
                                                                           215,666               210,995
    Weighted average common and common equivalent shares outstanding
                                                                      ==== ======= ====  ==== ========== ====

                                                      E
                                             XCO Resources, Inc.
                                    Consolidated statement of cash flows
                                                 (Unaudited)
                                                                               Three months ended
                                                                                    March 31,
                                                                    -----------------------------------------
(in thousands)                                                             2010                 2009
------------------------------------------------------------------  ------------------- ---------------------
Operating Activities:
Net income (loss)                                                      $  115,568          $ (1,099,611 )
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
  Depreciation, depletion and amortization                                 38,818                81,794
  Stock option compensation expense                                         4,609                 3,223
  Accretion of discount on asset retirement obligations                     1,089                 2,071
  Write-down of oil and natural gas properties                                  -             1,293,579
  Income from equity investment in TGGT Holdings, LLC                         (89 )                   -
  Non-cash change in fair value of derivatives                            (24,120 )            (128,741 )
  Cash settlements of assumed derivatives                                     907               (37,616 )
  Deferred income taxes                                                         -                 1,055
  Amortization of deferred financing costs and premium on 7 1/4%              (90 )              11,758
  senior notes due 2011
  Effect of changes in:
    Accounts receivable                                                   (40,548 )              43,862
    Other current assets                                                   (1,680 )              (1,152 )
    Accounts payable and other current liabilities                         (3,161 )             (64,896 )
                                                                         -------- ----       ---------- ----
Net cash provided by operating activities                                  91,303               105,326
                                                                         --------            ----------
Investing Activities:
Additions to oil and natural gas properties, gathering systems and       (124,223 )            (189,992 )
equipment
Property acquisitions                                                     (10,943 )                   -
Restricted cash                                                           (11,079 )                   -
Equity investment in TGGT Holdings, LLC                                   (44,500 )                   -
Proceeds from disposition of property and equipment                        66,925                 5,477
                                                                         --------            ----------
Net cash used in investing activities                                    (123,820 )            (184,515 )
                                                                         -------- ----       ---------- ----
Financing Activities:
Borrowings under credit agreements                                         39,960                34,963
Repayments under credit agreements                                        (24,981 )                   -
Proceeds from issuance of common stock                                      4,206                   447
Payment of common stock dividends                                          (6,364 )                   -
Settlements of derivative financial instruments with a financing             (907 )              37,616
element
Deferred financing costs and other                                              -                (5,468 )
                                                                         --------            ---------- ----
Net cash provided by financing activities                                  11,914                67,558
                                                                         --------            ----------
Net decrease in cash                                                      (20,603 )             (11,631 )
Cash at beginning of period                                                68,407                57,139
                                                                         --------            ----------
Cash at end of period                                                  $   47,804          $     45,508
                                                                    ==== ========       ==== ==========
Supplemental Cash Flow Information:
Cash interest payments                                                 $   21,041          $     48,933
                                                                    ==== ========       ==== ==========
Supplemental non-cash investing and financing activities:
  Capitalized stock option compensation                                $    1,105          $        507
                                                                    ==== ========       ==== ==========
  Capitalized interest                                                 $    2,915          $      1,361
                                                                    ==== ========       ==== ==========
  Issuance of common stock for director services                       $        9          $         17
                                                                    ==== ========       ==== ==========

                                                      E
                                             XCO Resources, Inc.
                                             Consolidated EBITDA
                       And adjusted EBITDA reconciliations and statement of cash flow
                                                    data
                                                 (Unaudited)
                                                                                 Three months ended
                                                                                      March 31,
                                                                       --------------------------------------
(in thousands)                                                               2010                2009
---------------------------------------------------------------------  ----------------- --------------------
   Net income (loss)                                                        $ 115,568         $ (1,099,611 )
   Interest expense                                                            10,634               36,132
   Income tax expense                                                               -                1,055
   Depreciation, depletion and amortization                                    38,818               81,794
                                                                              -------           ----------
EBITDA(1)                                                                     165,020             (980,630 )
   Accretion of discount on asset retirement obligations                        1,089                2,071
   Non-cash write-down of oil and natural gas properties                            -            1,293,579
   Equity method income in TGGT Holdings, LLC                                     (89 )                  -
                                                                              (22,102 )           (122,955 )
   Non-cash change in fair value of derivative financial instruments
   Stock based compensation expense                                             4,609                3,223
                                                                              -------           ----------
Adjusted EBITDA (1)                                                         $ 148,527         $    195,288
   Interest expense (2)                                                       (12,652 )            (41,918 )
   Income tax expense                                                               -               (1,055 )
                                                                                  (90 )             11,758
   Amortization of deferred financing costs, premium on 7 1/4% senior
   notes due 2011 and discount on long-term debt
   Deferred income taxes                                                            -                1,055
   Changes in operating assets and liabilities                                (45,389 )            (22,186 )
                                                                                  907              (37,616 )
    Settlements of derivative financial instruments with a financing
    element
                                                                              -------           ---------- -
Net cash provided by operating activities                                   $  91,303         $    105,326
                                                                       ====== =======    ====== ==========

                                           Three months ended
                                                March 31,
                                     -------------------------------
(in thousands)                            2010            2009
-----------------------------------  --------------- ---------------
Statement of cash flow data:
Cash flow provided by (used in):
   Operating activities               $   91,303      $  105,326
   Investing activities                 (123,820 )      (184,515 )
   Financing activities                   11,914          67,558
Other financial and operating data:
   EBITDA(1)                             165,020        (980,630 )
   Adjusted EBITDA(1)                    148,527         195,288

(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.

                                            E
                                   XCO Resources, Inc.
                                Summary of operating data
                                                           Three months ended
                                                                March 31,            %
                                                         -----------------------
                                                            2010        2009      Change
                                                         ----------- ----------- --------
Production:
                     Oil (Mbbls)                                159         527  -70 %
                     Gas (Mmcf)                              22,837      33,184  -31 %
                     Oil and natural gas (Mmcfe)             23,791      36,346  -35 %
Average sales prices (before derivative
                    financial instrument activities):
                    Oil (per Bbl)                          $  75.24    $  37.37  101 %
                    Gas (per Mcf)                              5.21        4.60   13 %
                    Total production (per Mcfe)                5.51        4.74   16 %
Average costs (per Mcfe):
                    Oil and natural gas operating costs    $   0.81    $   1.12  -28 %
                    Production and ad valorem taxes            0.33        0.34   -3 %
                    Gathering and transportation costs         0.47        0.11  327 %
                    Depletion                                  1.43        2.06  -31 %
                    Depreciation and amortization              0.20        0.19    5 %
                    G                                          1.11        0.57   95 %
                    eneral and administrative

SOURCE: EXCO Resources, Inc.

EXCO Resources, Inc.
Douglas H. Miller, Chairman, 214-368-2084
or
Stephen F. Smith, President, 214-368-2084
www.excoresources.com

By Nicholas McCrea

May 02, 2010

Original Article

At a public forum in DeWitt, Syracuse University hydrology professor Don Siegel thought he had presented enough unbiased, scientific information to prove that drilling for natural gas in New York would benefit the state far more than it might hurt.

Then someone in the audience of more than 75 stood up.

“With all due respect, Dr. Siegel,” she said, “it’s not about the science.”

Two months later, Siegel still stews over those words.

The debate should be about the science, he contends, as do two retired SU professors, Bryce Hand and Joe Robinson — who have defended high-volume hydraulic fracturing as a safe method to capture a huge supply of underground natural gas in the Marcellus Shale formation.

But opponents of hydrofracking have “dispensed with science and rely on fear” to turn the public against drilling, Siegel said.

The voices of scientists are being drowned out, the professors said.

“What I’m finding is that no matter how you make the argument about shale bed methane to the local community, they refuse to understand it or refuse to even consider it,” said Siegel, a 62-year-old Syracuse resident.

Hydrofracking opponents like Dereth Glance, executive program director for Citizens Campaign for the Environment, say the gas industry is pushing New York to permit large-scale hydrofracking before the state formulates regulations that will adequately protect the environment.

“It’s about science, it’s about policy, and it’s about precautionary principles,” Glance said.

But Siegel said environmental groups have been doing everything in their power to block what he believes is the best solution to avoid a far worse environmental problem.

For Siegel, who considers himself an environmentalist, climate change is looming large. He said switching to natural gas, the cleanest of the fossil fuels, could help slow its approach by cutting carbon dioxide emissions by 17 percent. It would satiate New York’s energy needs until alternative energy sources become more viable.

Robinson, Siegel and Hand said they are perplexed that people continue to fight wind farms, nuclear power plants, and other forms of alternative energy, while at the same time resisting natural gas drilling.

“You can’t stop the climate crisis from happening by doing nothing,” Siegel said. “It’s easy to say ‘No, no, no, no,’ but we’ve got a clean energy source right under our feet.”

State Department of Environmental Conservation Commissioner Pete Grannis said last month in Syracuse that he expects the DEC to issue its revised regulations on hydrofracking later this year and begin issuing permits by 2011.

But state Assemblyman Steve Englebright, a former curator of Geologic Collections at State University at Stony Brook, where he also earned a master’s degree in sedimentology/paleontology, is sponsoring a bill calling for a moratorium on hydrofracking in New York until after the Environmental Protection Agency completes a two-year study on its environmental impact.

Englebright isn’t the only one who wants to slow the natural gas rush.

“Not here. Not now. But not never,” said Tony Ingraffea, a Cornell University engineering professor who specializes in fracture mechanics and wants the state to conduct more research, strengthen its hydrofracking regulations and improve its enforcement capabilities.

Horizontal hydraulic fracturing involves drilling into the shale — at least 2,000 feet below ground — then turning the drill horizontally to continue the well, or several horizontal wells, from the vertical bore. Piping is fed into the well and encased in cement.

After that, the shale is fractured and a fluid mixture of about 99 percent water and sand, and 1 percent chemicals is pumped into the well. The sand holds open the fractures so gas can seep into the well. The chemicals usually act as thickeners and lubricants, allowing the fluid to work its way through the fissures.

The pressure of the thousands of feet of earth and rock above forces the gas and some of the fracking fluid into the well casing, where it’s extracted.

Among the concerns critics most frequently raise are the potential risk to groundwater supplies, the scarring of the natural landscape and degradation of roadways, but some scientists say many of those concerns have been sensationalized.

Opponents point to Dimock, Pa., a town 100 miles south of Syracuse, where hydrofracking is occurring. Recently, , the Department of Environmental Protection ordered Cabot Oil and Gas Corp. to pay fines and plug three wells that the DEP believes led to methane contaminating the drinking water of 14 Dimock homes. Cabot must also install permanent water treatment systems at each of those homes.”

Siegel, Hand and Robinson, a petroleum geologist, acknowledge that high-volume hydrofracking is not without risks.

But Hand, a sedimentologist who taught for 30 years at SU before retiring in 1999, said many of the concerns are being “overblown.”

“In every basin, there might be one or two accidents out of tens of thousands of wells,” Siegel said. He guessed that Cabot made a mistake when pumping the concrete that surrounds the well piping, allowing gas to seep up outside the casing and eventually travel into the 14 homes’ water supply.

However, he said he has not been able to find any data from Pennsylvania DEP about the water contamination or drilling mishap, which he would like the independent scientific community to be able to evaluate for itself.

He said Pennsylvania DEP’s reaction to this “atypical, rare” mishap should be encouraging to New York, as it will push other companies to not repeat Cabot’s mistakes and will improve the drilling process.Some scientists say New York should take great care and time before allowing extensive drilling.

During an April 22 Thursday Morning Roundtable session, Bruce Selleck, professor of geology at Colgate University, said he was “comforted” by the state’s caution in issuing drilling permits. He said the state should learn from drilling that’s happening in other places.

“In a way, New York is very lucky that Pennsylvania has been bleeding on the cutting edge of technology development for hydrofracking,” Selleck said.

Selleck suggested that before New York issues permits for drilling throughout the state, it should use an isolated area of the Southern Tier. as a testing ground. That would let the state assess the effects on the local environment.

Hand, Siegel and Robinson say some hydrofracking opponents are exaggerating the risk to water supplies posed by chemical additives that make up around 1 percent of the fracking fluids.

The professors said these chemicals range from common food additives to acids. The additives used vary from well to well. Robinson said the chemicals are so diluted that they wouldn’t pose a significant risk, and many of them dissolve underground and become harmless before gas companies bring fluids back to the surface.

Critics argue that since the fluids are used in such high volumes, usually a few million gallons per well, the chemicals can still be harmful.

Hydrofracking opponents also say the environment could be damaged by the high salt content in the fluid that flows back up the well after the drilling process. This flowback fluid is stored in surface pits at the well sites until it can be disposed of or reused in a new well.

A tear in the liners of these pits might lead to spills that find their way into local water supplies, causing the salt content to rise to unacceptable levels, Siegel acknowledged.

Siegel said the state lacks facilities to treat the saline flowback fluids. These facilities would need to be set up, or the state would need to allow the fluids to be stored in deep injection wells.

The SU professors agree that hydrofracking needs to be heavily regulated and that the DEC needs more staff to do this effectively.

“We really don’t have to be in any enormous rush,” said Hand, who said that even though he felt the concerns were overblown, he was comfortable with the state taking its time. “The gas will still be there, it’ll always be there, until we get it out.”