─ During the third quarter 2009, we closed divestiture transactions, including our joint venture transactions with BG Group, resulting in proceeds of approximately $1.4 billion. We used the proceeds to reduce debt by $1.4 billion, including full retirement of our $300 million Term Credit Agreement.

─ Our asset divestiture program continued during the third quarter 2009 as we entered into agreements to sell certain shallow assets located in Ohio and northwestern Pennsylvania and to sell the remaining assets in our Mid-Continent region. Both transactions are expected to close in November 2009 with aggregate proceeds of $685 million, subject to closing adjustments. The impact to our production from these last two sales is expected to be approximately 60 Mmcfe per day. Upon closing of these transactions, our divestiture program will be essentially complete.

─ Oil and natural gas production was 31.9 Bcfe, or 347 Mmcfe per day for the third quarter 2009 compared with 36.6 Bcfe, or 397 Mmcfe per day during the third quarter 2008 and 36.5 Bcfe, or 401 Mmcfe per day during the second quarter 2009. The reduced production volumes reflect the impact of our joint venture transaction with BG Group and other 2009 divestitures. The impact of the third quarter 2009 divestitures reduced production by approximately 125 Mmcfe per day for the last 48 days of the quarter.

─ Oil and natural gas revenues, as adjusted for the cash settlements of our derivative financial instruments (derivatives), a non-GAAP measure, were $239 million for the third quarter 2009 compared with $288 million for the second quarter 2009 and $332 million for the third quarter 2008. The lower revenues reflect realized price declines of 66% for natural gas and 45% for oil from the prior year's third quarter and the impacts of our 2009 divestitures. The impact of the lower commodity prices was significantly reduced by the cash settlements of our derivatives.

─ Adjusted net income available to common shareholders, a non-GAAP measure adjusting for unrealized derivative gains and losses, gains on divestitures and other non-cash items typically not included by securities analysts in published estimates, was $0.20 per diluted share for the third quarter 2009 compared with $0.23 per diluted share for the third quarter 2008.

─ Adjusted EBITDA, defined as earnings before interest, taxes, depreciation, depletion and amortization, gains from divestitures and other non-cash income and expense items (a non-GAAP measure) for the third quarter 2009 was $173 million compared with $249 million in the third quarter 2008.

─ In light of the continuing success of our Haynesville shale development and the closing of the joint venture with BG Group, we are planning to increase our development drilling and leasing activities in East Texas/North Louisiana. We now plan to spud 42 operated Haynesville wells and complete 27 of those wells as compared to our original plan to spud 27 operated wells, with completions totaling 20 wells in 2009. We expect our expenditures for 2009 will be approximately $535 million. If the estimated purchase price adjustment for capital expenditures since the effective date of the transactions with BG Group is considered, our 2009 capital expenditures would be approximately $400 million.

Douglas H. Miller, EXCO's Chairman and CEO, commented, "The third quarter may prove to be the most significant quarter in the history of our company. The combination of the joint venture transactions with BG Group and successful execution of our divestiture plan strengthened our balance sheet, allowing us to focus our investment strategy on areas with tremendous growth opportunities for years to come. Our new relationship with BG Group gives us access to a world-class partner with additional technical and financial resources as well as gas marketing expertise. The outstanding results from early development in the Haynesville shale confirm our excellent position in the play and have displayed the exceptional capabilities and dedication of our operating and technical staff. Our plan is to build on this success and leverage lessons learned as we continue to aggressively pursue our strong acreage positions in the Haynesville play and ramp up in Appalachia to develop our Marcellus shale position."

We continued to achieve outstanding drilling results in the Haynesville shale. We have completed 17 operated Haynesville horizontal wells this year; 8 of which were completed during the third quarter 2009. Our average operated completions in DeSoto Parish, Louisiana this year have resulted in average initial production rates exceeding 24 million cubic feet of natural gas per day.

For the remainder of 2009, we will continue increasing our drilling and completion activity in the Haynesville shale as we plan to spud an additional 25 operated wells. We are also continuing to evaluate our strong Marcellus shale position in Appalachia by drilling test wells, building our operating staff and developing our plans for 2010 and beyond. Increasing our activities in other areas will depend on strengthening of commodity prices.

For the nine months ended September 30, 2009, adjusted net income available to common shareholders was $0.68 per diluted share, equal to adjusted net income of $0.68 per diluted share for the nine months ended September 30, 2008. Adjusted EBITDA for the nine months ended September 30, 2009 was $578 million compared with $766 million for the nine months ended September 30, 2008, a decrease of approximately 25% due primarily to lower commodity prices in 2009.

Equivalent production for the nine months ended September 30, 2009 was 104.8 Bcfe, a decrease of 3% from the prior year's nine month period equivalent production of 107.5 Bcfe. The decrease in production reflects our divestitures, suspension of our vertical drilling activities and normal declines in our other operating areas, offset by favorable impacts from our Haynesville drilling program, during the nine months ended September 30, 2009.

The average price per barrel of oil, excluding derivatives, was $50.89 per Bbl for the nine months ended September 30, 2009 compared with $111.66 for the prior year's nine month period. The average natural gas price, excluding derivatives for the nine months ended September 30, 2009 and 2008 was $3.88 and $9.96 per Mcf, respectively, a decrease of approximately 61%.

Net Income

Our reported net income (loss) and net income (loss) available to common shareholders shown below, both GAAP measures, include certain items not typically included by securities analysts in their published estimates of financial results. Management is disclosing the non-GAAP measures of adjusted net income and adjusted net income available to common shareholders because it quantifies the financial impact of non-cash gains or losses resulting from derivatives, non-cash ceiling test write-downs, gains or losses on divestitures and other items management believes affect the comparability of our results of operations which are included in GAAP net income measures. The following table provides a reconciliation of our net income (loss) and net income (loss) available to common shareholders to non-GAAP measures of adjusted net income and adjusted net income available to common shareholders:

                                                                                               Three months ended                                             Nine months ended                                             
                                                                                               September 30, 2009             September 30, 2008              September 30, 2009              September 30, 2008            
 (in thousands, except per share amounts)                                                      Amount           Per share     Amount            Per share     Amount            Per share     Amount            Per share   
 Net income (loss), GAAP                                                                       $  433,330                     $  (146,329   )                 $  (738,273   )                 $  (572,082   )               
 Adjustments:                                                                                                                                                                                                               
 Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes                                                                                                                                   
                                                                                                  98,800                         (968,117   )                    144,996                         (59,004    )               
 Non-cash write down of oil and natural gas properties                                            -                              1,193,105                       1,293,579                       1,193,105                  
 Gain on divestitures                                                                             (460,626  )                    -                               (460,626   )                    -                          
 Income taxes on above adjustments (1)                                                            144,730                        (89,995    )                    (391,180   )                    (453,640   )               
 Adjustment to deferred tax asset valuation allowance (2)                                         (174,230  )                    63,302                          295,677                         63,302                     
 Total adjustments, net of taxes                                                                  (391,326  )                    198,295                         882,446                         743,763                    
 Adjusted net income                                                                           $  42,004                      $  51,966                       $  144,173                      $  171,681                    
                                                                                                                                                                                                                            
 Net income (loss) available to common shareholders, GAAP (3)                                     433,330       $  2.05          (153,326   )   $  (0.80  )      (738,273   )   $  (3.50  )      (649,079   )   $  (4.84  ) 
 Adjustments shown above (3)                                                                      (391,326  )      (1.85  )      198,295           1.04          882,446           4.18          743,763           5.55     
 Adjusted net income available to common shareholders                                             42,004                         44,969                          144,173                         94,684                     
 Dilution attributable to stock options (4)                                                       -                -             -                 (0.01  )      -                 -             -                 (0.03  ) 
 Adjusted net income available to common shareholders for diluted earnings per share           $  42,004        $  0.20       $  44,969         $  0.23       $  144,173        $  0.68       $  94,684         $  0.68     
                                                                                                                                                                                                                            
 Common stock and equivalents used for adjusted earnings per share (EPS):                                                                                                                                                   
 Weighted average common shares outstanding                                                       211,266                        191,452                         211,118                         134,006                    
 Dilutive stock options                                                                           1,969                          5,321                           638                             4,834                      
 Shares used to compute diluted EPS for adjusted net income available to common shareholders                                                                                                                                
                                                                                                  213,235                        196,773                         211,756                         138,840                    


-------------------------------------------------------------------------------

(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 outstanding.

(4) Represents dilution per share attributable to common stock equivalents from in-the-money stock options for periods with adjusted net income available to common shareholders.

Operations activity and outlook

We spent $61 million on development and exploitation activities, drilling and completing 16 gross (6.4 net) wells in the third quarter 2009, compared with 22 gross (13.7 net) wells during the second quarter 2009. We had an overall drilling success rate of 100% for the third quarter 2009. Our total capital expenditures, including leasing, midstream and corporate activities, were $129 million in the third quarter 2009. We currently have 13 drilling rigs operating across our portfolio, which is an increase from 6 drilling rigs operating at the end of the second quarter 2009. The increase is due to our increased focus and activity in our Haynesville, Bossier and Marcellus shale plays. Although we expect our fourth quarter 2009 leasing, drilling and completion activities in East Texas and North Louisiana area to increase, our actual total expenditures for 2009 will be approximately $400 million, net of the capital recovery from purchase price adjustments with BG Group. We will continue to focus our capital expenditures in areas that will provide strong returns in the current commodity price environment.

East Texas/North Louisiana

On August 14, 2009, we closed our joint venture development transaction with BG Group which included a sale of 50% of our interest in most of our wells and developed assets in the East Texas/North Louisiana area. The transaction excluded our Vernon Field, which is currently our largest net producing area.

East Texas/North Louisiana is our largest division in terms of production and reserves, and our primary targets across this region include the Haynesville shale, the upper and lower Cotton Valley, Travis Peak, Pettet and Hosston formations. Currently, our emphasis is exploitation of our Haynesville shale play position. In East Texas/North Louisiana, during the third quarter 2009, we drilled and completed 8 gross (2.3 net) operated wells and 4 gross non-operated wells in which we hold a small working interest.

Haynesville Shale

During the third quarter 2009, our horizontal Haynesville Shale development program yielded exceptional results with some of the highest production rates in the play. In addition to the 8 operated horizontal Haynesville wells drilled and completed during the third quarter 2009, we have 5 gross (1.7 net) currently in the completion phase and 10 gross (3.4 net) drilling. Our average initial production rates in DeSoto Parish were 24.8 Mmcf per day for wells completed during the third quarter, with a range of 20.5 to 30.1 Mmcf per day. We started the quarter with 4 operated drilling rigs and ended the quarter with 7 operated drilling rigs. We recently added 3 additional drilling rigs bringing our total current operated horizontal rig count to 10. We plan to exit 2009 with 11 operated rigs.

We also hold small working interests in Haynesville wells operated by others. During the third quarter 2009, we participated in 2 gross non-operated wells in DeSoto Parish, Louisiana with initial gross production rates averaging 19.4 Mmcf per day and 1 gross well in Caddo Parish, Louisiana with an initial gross production rate of 7.8 Mmcf per day. At the end of the third quarter, we had interests in 5 gross non-operated horizontal Haynesville shale wells being drilled in DeSoto Parish, Louisiana.

We currently have 18 gross (6.0 net) operated horizontal wells and 9 gross (0.7 net) non-operated horizontal wells flowing to sales. Production from our Haynesville wells recently reached a combined gross rate of 185 Mmcf per day (42 Mmcf per day net).

Our DeSoto Parish area has yielded the highest production rates in the entire play, with two of our most recent completions yielding initial gross production rates of 29.6 and 30.1 Mmcf per day. The EXCO operated average initial gross production rate in DeSoto Parish is 24.1 Mmcf per day, with all of our DeSoto Parish wells having initial production rates in excess of 20.5 Mmcf per day. This high level of performance over a broad area underscores the consistency and high quality of the shale reservoir on our acreage and also demonstrates the effectiveness of our target selection and completion design.

Our drilling and completion times are continuing to improve as we focus on operational efficiencies. Our initial wells took 70 to 75 days from spud to rig release and our most recent well took 39 days from spud to rig release. Drilling and completion time is important, but we believe it is far more important to achieve a well placed lateral in the target zone over the entire lateral length. Also, proper hole conditioning prior to running casing is a key factor we have focused on and to date, we have achieved a 100% success rate on running casing to drilled total depth in all of our operated horizontal wells. All of our operated wells have flowed to sales immediately following completion operations due to close coordination with our midstream business.

The Bossier Shale that overlies the Haynesville Shale is another significant target interval that EXCO is beginning to exploit. In DeSoto Parish, the Bossier is over 1,500 feet in gross thickness, compared to 300-400 feet of gross thickness in the Haynesville. We have acquired over 900 feet of whole core in the Bossier Shale to date in two wells and currently have a rock property testing program underway. We are currently testing the Bossier Shale in 6 counties and parishes in East Texas and North Louisiana and have seen encouraging results. We plan to spud our first horizontal Bossier well late in the fourth quarter 2009.

Cotton Valley

In the third quarter 2009, we drilled and completed 1 gross non-operated Cotton Valley horizontal well. With current natural gas prices at the lowest levels in several years, we have elected to suspend most of the operated Cotton Valley drilling.

Appalachia

On September 29, 2009, we announced an agreement to sell approximately 3,200 wells located in northwestern Pennsylvania and Ohio for $145 million, subject to customary closing adjustments. We expect the sale to close in November 2009.

Upon closing of the aforementioned sale, we will hold in excess of 639,000 net leasehold acres. Our major operating areas will include Pennsylvania and West Virginia, where we historically drilled for the Clinton/Medina sandstone, stacked Devonian sandstone, Devonian shale, Berea shale and other productive horizons. Included as a subset of our acreage position, we now control approximately 348,000 acres in the Marcellus shale fairway, with more than 223,000 acres located in the core area of the over pressured Marcellus. A significant percentage of this fairway acreage is held by production (HBP) by our shallow producing assets. Also as a subset of our acreage position, we control 130,000 acres (70% HBP) within the Huron Shale play of West Virginia. We believe our present leasehold position in the Marcellus and Huron Shale fairways contains between 7 to 12 TCF of potential reserves. Throughout 2009, our technical Marcellus activity is focused on integrating technical data from our 2008 and 2009 Marcellus well results and seismic data, delineating our acreage blocks using our updated geological model and drilling and completing test wells to high grade for a 2010 development program. We drilled and completed 4 gross (4.0 net) vertical wells in Appalachia during the third quarter 2009.