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EXCO Resources, Inc. Reports Operating and Financial Results for the Third Quarter of 2008

Posted on: Wednesday, 5 November 2008, 18:00 CST

EXCO Resources, Inc. (NYSE: XCO) today announced third quarter of 2008 results.

-- Adjusted net income available to common shareholders, a non-GAAP measure adjusting for non-cash derivative gains or losses, non-cash ceiling test write-down and other items typically not included by securities analysts in published estimates, was $0.23 per diluted share for the third quarter of 2008 compared with an adjusted net loss of $0.20 per share for the third quarter of 2007.

-- Oil and natural gas revenues for the third quarter of 2008 were $402 million, exclusive of derivative financial instrument activities (derivatives) and $332 million inclusive of cash settlements on derivatives. Oil and natural gas revenues for the prior year's quarter were $228 million before derivatives, and $275 million including cash settlements on derivatives.

-- Oil and natural gas production for the third quarter of 2008 was a record 37 Bcfe, or 397 Mmcfe per day comprised of 359 Mmcf per day of natural gas and 6,413 barrels of oil per day. Production for the third quarter of 2008 was negatively impacted by approximately 3.2 Mmcfe per day from Hurricane Ike. Despite the loss of these volumes, our volumes were in line with our expectations and previously issued guidance. Normalized production of approximately 400 Mmcfe per day, which includes the lost volumes from the hurricane, represented an increase of 2% from the prior quarter. Presently our daily average production totals 406 Mmcfe per day.

-- Direct operating expenses, excluding non-cash stock-based compensation expense, were $1.13 per Mcfe for the third quarter of 2008, of which $1.04 per Mcfe was attributable to recurring lease operating expenses and $0.09 per Mcfe was attributable to workover expenses. The quarterly results include effects of higher chemicals, labor, utilities and other operating expense increases arising from increased commodity prices during the first, second and a majority of the third quarter of 2008. Additionally, we estimate that Hurricane Ike negatively impacted our unit operating costs by approximately $0.01 per Mcfe.

-- Midstream operating profit, before the effect of intercompany eliminations, was $8 million compared with $7 million in the prior year's quarter.

-- 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 was $249 million, approximately 16% higher than the prior year's quarter.

-- Total capital expenditures for the third quarter of 2008, which include drilling and development, leasing, midstream projects and corporate expenditures, were $307 million, an increase of 119% from the prior year's quarter. Drilling and development capital expenditures totaled $201 million for the third quarter of 2008 compared with third quarter of 2007 drilling and development capital expenditures of $124 million. During the second quarter of 2008, we initiated an aggressive acreage acquisition program, particularly in our shale plays in the Haynesville/Bossier (Haynesville) in East Texas/North Louisiana and the Marcellus in Appalachia. Year-to-date leasehold expenditures were $177 million, $75 million of which was during the third quarter of 2008. As of September 30, 2008, our significant leasehold acquisition program is effectively complete.

-- On July 18, 2008, we converted all outstanding shares of our preferred stock into a total of approximately 105 million shares of our common stock. The conversion of the preferred stock had the effect of increasing the book value of shareholders' equity by approximately $2.0 billion. On July 21, 2008, we paid all accrued dividends plus cash in lieu of fractional shares upon conversion totaling approximately $13 million to the holders of the converted shares of preferred stock. After July 18, 2008, dividends ceased to accrue on the preferred stock and all rights of the holders with respect to the preferred stock terminated. The conversion of all outstanding shares of preferred stock into common stock eliminated our obligation to pay quarterly cash dividends of $35 million, resulting in annual dividend savings of $140 million.

-- During the third quarter of 2008, our GAAP earnings were impacted by net, non-cash, after-tax losses of approximately $204 million representing a pre-tax ceiling test write-down of $1,193 million ($723 million after-tax) of our oil and natural gas properties which was largely offset by a pre-tax mark-to-market gain of $970 million ($582 million after-tax) on our derivative financial instruments. The impact of the write-down to our oil and natural gas properties and changes in the fair value of derivatives also resulted in recognition of a $63 million income tax valuation allowance. The interplay of the decrease in commodity prices at the end of the third quarter which resulted in the ceiling test write-down and the significant gains from our derivative financial instruments demonstrates the importance of our hedging program. However, since we do not designate our derivative financial instruments as hedges, we do not include their impacts when computing the ceiling on capitalized cost and, when prices decline, we do not include any favorable impact from derivative financial instruments in the computation. None of these non-cash items affected our liquidity or compliance with bank covenants.

Douglas H. Miller, EXCO's Chief Executive Officer, commented, "Our strong operating performance continued during the third quarter with record average production of 397 Mmcfe per day, which would have exceeded 400 Mmcfe per day excluding the effects of Hurricane Ike. Present production is approximately 406 Mmcfe per day. Revenues and cash flows were also strong due to favorable pricing of oil and natural gas during the quarter. Even though oil and natural gas prices began declining during the quarter and have continued to weaken, our significant hedge position in 2008 and 2009 is serving to greatly reduce the impact of the lower prices.

"We continue to drill in all significant areas of our portfolio with increased emphasis in the Haynesville, Marcellus and Huron shale areas. We have begun to release rigs in certain conventional drilling areas and expect reductions in planned drilling expenditures in the fourth quarter of 2008 of approximately 10-15%. Including these reductions in our expected drilling activity for the fourth quarter of 2008 and completion of our leasing and midstream capital projects, our total capital spending in the fourth quarter will be a reduction of approximately 35% from the third quarter of 2008 levels. The results of our shale drilling programs are very encouraging, and we look forward to the first horizontal Haynesville results in the next two to three weeks.

"We are evaluating the sale of non-core assets throughout our portfolio and have begun a formal sales process for certain East Texas assets. Due to current market conditions, we have terminated the joint venture process announced in July; however, we may pursue certain joint ventures in the future if market conditions warrant.

"On October 20, 2008, we received a reaffirmation of our $2.5 billion borrowing base under our revolving credit agreement from our lenders. We are in discussions with our lenders to refinance, renew and extend our $300 million Term Loan, which we expect to complete on or before the existing maturity date. This refinancing, renewal and extension requires approval by a majority of the lenders under the EXCO Operating Company revolving credit agreement.

"We are currently finalizing our capital spending plans for 2009. We will continue to set our budget at an amount which can be fully funded within our projected cash flow. Obviously, commodity prices are a significant factor in setting and maintaining capital spending. However, we expect our discipline of not spending more than our cash flow and our hedge position to provide adequate capital to exploit our significant inventory of drilling locations with particular emphasis on the Haynesville and Marcellus shale assets."

For the nine months ended September 30, 2008, adjusted net income available to common shareholders was $0.68 per diluted share compared with an adjusted net loss of $0.23 per diluted share for the nine months ended September 30, 2007. Adjusted EBITDA for the nine months ended September 30, 2008 was $766 million compared with $538 million for the nine months ended September 30, 2007, an increase of 42%.

Equivalent production for the nine months ended September 30, 2008 was 108 Bcfe, an increase of 24% from the prior year's nine month period equivalent production of 87 Bcfe. The increase in production is primarily attributable to a full nine months of volumes from our 2007 acquisitions of Vernon and Southern Gas, while the 2007 nine months contain only six months of Vernon and five months of Southern Gas production.

The average price per barrel of oil, excluding derivatives, was $111.66 per Bbl for the nine months ended September 30, 2008 compared with $64.36 per Bbl for the prior year's nine month period. The average natural gas price, excluding derivatives for the nine months ended September 30, 2008 and 2007 was $9.96 and $6.72 per Mcf, respectively, an increase of approximately 48%.

Revenues and Adjusted Revenues

Our third quarter of 2008 adjusted revenues, a non-GAAP measure defined as revenues which exclude the non-cash impact of our oil and natural gas derivatives, were $361 million, an increase of $80 million, or 28% above the third quarter of 2007. The increase was primarily attributable to higher product prices, before derivatives, which increased by 66% on a per Mcfe basis over the prior year's quarter. Realized prices, after cash settlements on derivatives, were $9.09 per Mcfe and $7.97 per Mcfe for the three months ended September 30, 2008 and 2007, respectively.

Three months ended September 30, % --------------------- (in thousands, except prices) 2008 2007 change ----------------------------------------- ----------- --------- ------ Oil and natural gas revenues, before derivative financial instruments $ 402,384 $228,316 76% Cash settlements on derivative financial instruments (70,019) 46,249 ----------- --------- Subtotal, revenues including cash settlements on derivative financial instruments 332,365 274,565 21% Non-cash gain (loss) on oil and natural gas derivative financial instruments 970,332 52,003 ----------- --------- Oil and natural gas revenues 1,302,697 326,568 Midstream revenues 27,004 4,432 509% Other income 1,820 2,417 -25% ----------- --------- Total revenues, marketing and other income, GAAP 1,331,521 333,417 Elimination of non-cash oil and natural gas derivative financial instrument activity included in GAAP revenues (970,332) (52,003) ----------- --------- Adjusted revenues (1) $ 361,189 $281,414 28% =========== ========= Prices, excluding marketing and other income: ----------------------------------------- Realized price per Mcfe, before derivative financial instruments $ 11.01 $ 6.63 66% Realized price per Mcfe, after cash settlements on derivative financial instruments $ 9.09 $ 7.97 14% Nine months ended September 30, % --------------------- (in thousands, except prices) 2008 2007 change ----------------------------------------- ----------- --------- ------ Oil and natural gas revenues, before derivative financial instruments $1,155,978 $610,227 89% Cash settlements on derivative financial instruments (157,383) 84,951 ----------- --------- Subtotal, revenues including cash settlements on derivative financial instruments 998,595 695,178 44% Non-cash gain (loss) on oil and natural gas derivative financial instruments 53,849 (4,821) ----------- --------- Oil and natural gas revenues 1,052,444 690,357 Midstream revenues 61,852 14,189 336% Other income 5,496 7,579 -27% ----------- --------- Total revenues, marketing and other income, GAAP 1,119,792 712,125 Elimination of non-cash oil and natural gas derivative financial instrument activity included in GAAP revenues (53,849) 4,821 ----------- --------- Adjusted revenues (1) $1,065,943 $716,946 49% =========== ========= Prices, excluding marketing and other income: ----------------------------------------- Realized price per Mcfe, before derivative financial instruments $ 10.75 $ 7.04 53% Realized price per Mcfe, after cash settlements on derivative financial instruments $ 9.29 $ 8.02 16% (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 revenue is a meaningful measure to investors and rating agencies as it presents 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 and execute our capital program.

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 $212 million, or a 15% increase from the prior year's third quarter. We utilized this cash flow, supplemented by net borrowings under our revolving credit facilities, primarily to fund our development and exploitation projects and acquire acreage in our Haynesville/Bossier and Marcellus shale plays.

Three months ended Nine months ended September 30, % September 30, % ------------------- ------------------- (in thousands) 2008 2007 change 2008 2007 change ---------------- --------- --------- ------ --------- --------- ------ Cash flow from operations, GAAP $299,783 $211,172 $812,017 $380,298 Net change in working capital (53,559) (22,379) (49,786) 35,318 Settlements of derivative financial instruments with a financing element (34,405) (4,342) (96,504) (8,020) --------- --------- --------- --------- Cash flow from operations before changes in working capital, non- GAAP measure (1) $211,819 $184,451 15% $665,727 $407,596 63% ========= ========= ========= ========= (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 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 (loss) and adjusted net income (loss) available to common shareholders because it quantifies the financial impact of non-cash gains or losses resulting from derivatives, non-cash ceiling test write-downs and other items management believes affect the comparability of our results of operations which are included in GAAP net income measures. The following table provides a reconciliation of our net income (loss) and net income (loss) available to common shareholders to non-GAAP measures of adjusted net income (loss) and adjusted net income (loss) available to common shareholders:

Three months ended Three months ended September 30, 2008 September 30, 2007 --------------------- ------------------- (in thousands, except per share amounts) Amount Per share Amount Per share ---------------------------- ----------- --------- --------- --------- Net income (loss), GAAP $ (146,329) $ 56,462 Adjustments: Non-cash mark-to-market (gains) losses on oil and natural gas derivative financial instruments, before taxes (970,332) (52,003) Non-cash mark-to-market (gains) losses on interest rate derivative financial instruments, before taxes 2,215 - Non-cash write down of oil and natural gas properties 1,193,105 - Nonrecurring financing costs, before taxes - - Income taxes on above adjustments (1) (89,995) 20,801 Deferred tax asset valuation allowance 63,302 - ----------- --------- Total adjustments, net of taxes 198,295 (31,202) ----------- --------- Adjusted net income $ 51,966 $ 25,260 =========== ========= Net income (loss) available to common shareholders, GAAP (2) $ (153,326) $ (0.80) $ 10,729 $ 0.10 Adjustments shown above 198,295 1.04 (31,202) (0.30) Dilution attributable to stock options (3) - (0.01) - - ----------- --------- --------- --------- Adjusted net income (loss) available to common shareholders $ 44,969 $ 0.23 $(20,473) $ (0.20) =========== ========= ========= ========= Common stock and equivalents used for earnings per share (EPS): ---------------------------- Weighted average common shares outstanding 191,452 104,415 Dilutive stock options 5,321 - Dilutive preferred stock - - --------- --------- Shares used to compute diluted EPS for adjusted net income (loss) available to common shareholders 196,773 104,415 ========= ========= Nine months ended Nine months ended September 30, 2008 September 30, 2007 --------------------- ------------------- (in thousands, except per share amounts) Amount Per share Amount Per share ---------------------------- ----------- --------- --------- --------- Net income (loss), GAAP $ (572,082) $ 51,651 Adjustments: Non-cash mark-to-market (gains) losses on oil and natural gas derivative financial instruments, before taxes (53,849) 4,821 Non-cash mark-to-market (gains) losses on interest rate derivative financial instruments, before taxes (5,155) - Non-cash write down of oil and natural gas properties 1,193,105 - Nonrecurring financing costs, before taxes - 32,100 Income taxes on above adjustments (1) (453,640) (14,769) Deferred tax asset valuation allowance 63,302 - ----------- --------- Total adjustments, net of taxes 743,763 22,152 ----------- --------- Adjusted net income $ 171,681 $ 73,803 =========== ========= Net income (loss) available to common shareholders, GAAP (2) $ (649,079) $ (4.84) $(46,317) $ (0.44) Adjustments shown above 743,763 5.55 22,152 0.21 Dilution attributable to stock options (3) - (0.03) - - ----------- --------- --------- --------- Adjusted net income (loss) available to common shareholders $ 94,684 $ 0.68 $(24,165) $ (0.23) =========== ========= ========= ========= Common stock and equivalents used for earnings per share (EPS): ---------------------------- Weighted average common shares outstanding 134,006 104,311 Dilutive stock options 4,834 - Dilutive preferred stock - - --------- --------- Shares used to compute diluted EPS for adjusted net income (loss) available to common shareholders 138,840 104,311 ========= ========= (1) The assumed income tax rate is 40% for all periods. (2) Per share amounts are based on weighted average number of common shares outstanding. (3) 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. None of the Preferred Stock, which was issued on March 30, 2007 and converted into common stock on July 18, 2008, was dilutive for any of the periods.

Capital Activity and Outlook

We spent $201 million on development and exploitation activities, drilling and completing 145 gross (118.8 net) wells in the third quarter of 2008. Our overall drilling success rate exceeded 99%. Our total capital expenditures, including leasing, midstream and corporate activities, totaled $307 million. We currently have 25 drilling rigs operating across our portfolio, which we have reduced from 32 drilling rigs earlier in the third quarter of 2008 in response to lower commodity prices.

During the fourth quarter of 2008, we have reduced some of our budgeted conventional drilling activity to focus on our shale and midstream opportunities. Accordingly, our plan to drill and complete 608 gross wells has been reduced to drill and complete 512 wells during 2008. The following table details our revised capital spending outlook for 2008 for each of our significant regions:

Q1 - Q3 Actual Q4 2008 (in millions) Spent Estimate Total ----------------------------------- ----------- ---------- ----------- East Texas/North Louisiana $ 370 $ 94 $ 464 Appalachia 164 30 194 Mid-Continent 50 16 66 Permian/Rockies 84 29 113 Midstream 41 10 51 Corporate and other 40 13 53 ----------- ---------- ----------- Total $ 749 $ 192 $ 941 =========== ========== ===========

Of the $941 million forecast spending for 2008, over $170 million has been spent on leasing acreage and $86 million will be spent on drilling and completing wells on our shale assets. This shale drilling activity was comprised predominantly of vertical tests to delineate the shales and refine our horizontal development plans.

We anticipate presenting to our Board of Directors a 2009 capital budget program that will be fully funded within our 2009 expected cash flow. The expected activity level in 2009 will differ from 2008 with an emphasis on horizontal shale development, minimal leasing and continued midstream development in East Texas/North Louisiana and Appalachia. Assuming $6.50 per Mcf natural gas and $65.00 per Bbl oil prices, with current drilling costs we would also expect to reduce our conventional drilling program from our 2008 level of activity. We also expect to focus our conventional technical teams on exploitation projects to minimize the base decline of our properties. We will provide full guidance after the board has approved the capital spending program.

We are continuing with plans to sell certain producing assets over the next twelve months, beginning with a sale managed by Tristone Capital which was launched in October 2008 for certain non-core assets in East Texas with daily production of 24 Mmcfe per day. Although specific additional sales have not been announced, proceeds of all sales will be used to reduce debt and allow more capital to be focused on our shale development activities.

East Texas/North Louisiana

East Texas/North Louisiana is our largest division in terms of production and reserves, and our primary targets across this region have been the upper and lower Cotton Valley, Travis Peak, Pettet and Hosston formations. While we are continuing our original plan to drill and exploit these formations, we are increasing emphasis and expanding our activity in our Haynesville shale play position. Our 2008 capital spending outlook for the division totals $464 million, with $90 million allocated to Haynesville shale activities (primarily leasing, drilling and completion activity).

A significant amount of our Haynesville shale acreage is held by production (HBP), and is within areas of the play which have been proven productive by both our and our competitors' drilling and completion activities. Our current plans for 2008 include drilling 10 vertical and five horizontal Haynesville tests, of which two of the horizontal wells will be drilled by other operators. We expect two of the Haynesville wells to be completed in 2008. We have strategically focused on adding to our leasehold and on drilling to delineate the shale play rather than focusing on maximizing production from the shales. By the end of the third quarter, we had drilled eight vertical wells and spud two horizontal wells in the play. Our drilling to date in Harrison County, Texas and Caddo and DeSoto Parishes, Louisiana has identified Haynesville/Bossier shale thickness averaging 200 feet of net pay with high porosities and total organic carbon indicating significant gas in place. The shale quality, thickness and overall rock properties across our acreage have been very consistent based on our data and information from competitor activity. Recent tests of our Branch Ranch 31-1 and Lee 19-1 vertical wells located in DeSoto Parish, Louisiana had flowing casing pressures of 6,100 Psi and 6,600 Psi and flow rates from single stage fracture stimulation of approximately 1.3 Mmcfe per day and 1.0 Mmcfe per day, respectively. In our first operated horizontal well in DeSoto Parish, we successfully cored in the Haynesville shale. The core is currently in the evaluation laboratory where rock mechanics testing and other detailed studies are in progress. In the pilot hole we found approximately 200 feet of pay in the Haynesville shale. We drilled the well to a total measured depth of 16,083 feet, including a lateral section of 4,481 feet. We have run casing in the well and plan to complete the well in November 2008. Our second horizontal well in DeSoto Parish is being drilled by another operator and is projected to be completed in late November. Based on our results, we are planning increased activity in the Haynesville shale in 2009, and accordingly have signed long-term commitments with drilling contractors for four additional rigs capable of drilling horizontal Haynesville wells.

In addition to the 15 shale wells mentioned above, we plan to drill 135 conventional wells during 2008 in the East Texas/North Louisiana division. We currently have 13 rigs operating in the region, with four of these rigs drilling in our Vernon Field in Jackson Parish, Louisiana, where we continue to expand our field limits with successful step out drilling. We are evaluating seismic on 35,000 acres immediately north of the Vernon Field, with plans to spud a Cotton Valley test well in early 2009. We have five rigs operating in our Shreveport area, which includes our Holly/Caspiana Field and our Longwood/Greenwood/Waskom area. Our Holly/Caspiana Field has significant drilling activity in the traditional Cotton Valley and Hosston plays and both areas have significant Haynesville opportunities. We have two rigs running in our newly acquired Danville Field in Gregg County, Texas and are currently performing microseismic fracture mapping to aid in well placement to optimize recovery from the field. We plan to spend $20 million and drill nine wells during 2008 in Danville. During the third quarter of 2008, we drilled and completed 42 gross (28.9 net) wells in the East Texas/North Louisiana area with a 100% success rate.

Appalachia

In Appalachia, our major operating areas include Pennsylvania, Ohio, and West Virginia, where we typically drill for and exploit the Clinton/Medina sandstone, stacked Devonian sandstones, Devonian shales, Berea shale and other productive horizons. During the third quarter of 2008, we achieved a 100% drilling success rate on the 52 gross (47.8 net) wells drilled on our Appalachian properties. Year-to-date, we have drilled 107 gross (98.5 net) wells and achieved a 99% success rate. Significant efforts continue to evaluate and develop our Marcellus and Huron Shale position in Pennsylvania and West Virginia, respectively. During calendar year 2008, we expect to drill in excess of 150 wells to exploit the more conventional Clinton/Medina sandstone, stacked Upper Devonian sandstones, Devonian shale and Berea shale reservoirs found within our major operating areas of Pennsylvania, Ohio and West Virginia. Overall this represents a reduction in planned drilling as a result of reallocating capital to our shale activities. During the third quarter, twelve wells were spud in the shale program; two horizontal and five vertical wells in the Marcellus and five horizontal wells in the Huron. During the last quarter of 2008, shale exploitation and development activities will continue with the drilling of four additional horizontal Huron wells and three vertical Marcellus wells. At the end of the third quarter of 2008, we had ten drilling rigs active; seven were pursuing conventional targets, and three were pursuing shale targets. We have recently reduced our drilling activity to only six drilling rigs; two are pursuing conventional targets, and four are pursuing shale targets.

As we continue to ramp up our Marcellus Shale drilling efforts to delineate our acreage throughout the overpressured fairway, we have begun our completion efforts. Our first two Litke wells, located in Centre County in central Pennsylvania, were successfully fracture stimulated with strong initial flowback results. The Litke 2H well was completed with a single-stage fracture stimulation as the lateral section of the well was shorter than anticipated due to natural faulting of the rock. The initial flow rate from the well was 1.0 Mmcfe per day, and gas analysis indicates a high methane percentage, dry gas that falls well within pipeline quality specifications. Processing of heavier end natural gas or liquid components is unnecessary, and we are currently flowing unrestricted into a sales pipeline. The Litke 1H well has been completed with a four-stage fracture stimulation and although the well is still unloading fluid, it is currently flowing at a rate of 2.6 Mmcfe per day.

We have completed five horizontal wells in the West Virginia Huron shale play and have had spot production rates in excess of 400 Mcf per day which is in-line with expectations. Also, successful testing of the Marcellus and Huron has been conducted on several wells located in the shallower, normal to under-pressured areas of the basin where Marcellus and Huron production is being commingled with other, more traditional producing horizons to improve overall well economics. No dry holes have been drilled, nor have we lost any shale wells due to mechanical failure.

Other

Our Permian Canyon Sand field development and extension work is continuing. We drilled and completed 35 gross (32.1 net) wells in our Permian area, all of which were in our Canyon Sand Field, in the third quarter and achieved a 97% success rate on our drilling. We plan to drill a total of 124 wells in the field during 2008. Of the $113 million expected spending for the Permian Area in 2008, approximately $80 million is allocated for drilling and completion in the Canyon Sand field where we have three drilling rigs operating. In the first quarter 2008, we finalized a joint venture including approximately 11,000 contiguous net acres adjacent to this field, and we have acquired and are presently evaluating 3-D seismic data over this 11,000 acre block and plan to drill at least two wells in this area in early 2009. In the third quarter of 2008, we leased an additional 35,000 net acres adjacent to our Canyon Sand field and plan to acquire 3-D seismic over this acreage by year-end 2008. Our total leasehold in the Canyon Sand field now exceeds 77,700 net acres.

Our Mid-Continent division had periods of record production during the third quarter of 2008, with daily volumes approaching 70 Mmcfe per day.

Midstream

During the third quarter of 2008, we completed the 57-mile, $38 million expansion of our TGG intrastate pipeline system in East Texas. The extension is predominantly comprised of 20 inch pipe. With compression, incremental throughput capacity could exceed 530 Mmcf per day. In addition to the 20 inch expansion, our acquisition of assets in East Texas that we closed in July 2008 increased our Talco midstream assets by approximately 50 miles and 25 Mmcf per day of throughput.

Financial Data

Our condensed consolidated balance sheets as of September 30, 2008 (unaudited) and December 31, 2007, unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2008 and 2007, and unaudited condensed consolidated statements of cash flows for the nine months ended September 30, 2008 and 2007, 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 Thursday, November 6, 2008 at 10:00 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#65986498. 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 Wednesday, November 5, 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., November 13, 2008. Please call 800-642-1687 and enter conference ID# 65986498 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, the availability of capital from our revolving credit facilities and liquidity from capital markets. 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 September 30, December 31, (in thousands) 2008 2007 ------------------------------------------- ------------- ------------ (Unaudited) Assets Current assets: Cash and cash equivalents $ 95,135 $ 55,510 Accounts receivable: Oil and natural gas 181,011 146,297 Joint interest 12,349 21,614 Interest and other 4,576 2,151 Derivative financial instruments 60,259 66,632 Deferred income taxes - 6,764 Inventory 33,527 3,686 Other 13,214 8,646 ------------- ------------ Total current assets 400,071 311,300 ------------- ------------ Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties 541,892 334,803 Proved developed and undeveloped oil and natural gas properties 4,919,404 4,926,053 Accumulated depletion (829,372) (500,493) ------------- ------------ Oil and natural gas properties, net 4,631,924 4,760,363 ------------- ------------ Gas gathering assets 470,720 340,706 Accumulated depreciation and amortization (28,034) (16,142) ------------- ------------ Gas gathering assets, net 442,686 324,564 ------------- ------------ Office and field equipment, net 23,851 20,844 Advance on pending acquisition - 39,500 Derivative financial instruments 28,324 2,491 Deferred financing costs, net 17,458 20,406 Other assets 880 6,226 Goodwill 470,077 470,077 ------------- ------------ Total assets $ 6,015,271 $ 5,955,771 ============= ============

EXCO Resources, Inc. Condensed consolidated balance sheets September 30, December 31, (in thousands, except per share data) 2008 2007 ------------------------------------------- ------------- ------------ (Unaudited) Liabilities and shareholders' equity Current liabilities: Accounts payable and accrued liabilities $ 162,510 $ 106,305 Accrued interest payable 15,452 21,835 Revenues and royalties payable 136,927 100,978 Income taxes payable 202 87 Senior unsecured term credit agreement 300,000 - Current portion of asset retirement obligations 1,787 1,656 Derivative financial instruments 51,064 47,306 ------------- ------------ Total current liabilities 667,942 278,167 ------------- ------------ Long-term debt 2,685,649 2,099,171 Asset retirement obligations and other long-term liabilities 109,149 89,810 Deferred income taxes - 271,398 Derivative financial instruments 65,903 109,205 Commitments and contingencies - - 7.0% Cumulative Convertible Perpetual Preferred Stock, $0.001 par value, 39,008 shares outstanding at December 31, 2007, liquidation preference of $391,218 (1) - 388,574 Hybrid Preferred Stock, $0.001 par value, 160,992 shares outstanding at December 31, 2007, liquidation preference of $1,614,616 (1) - 1,603,704 Shareholders' equity: Preferred stock, $0.001 par value; authorized shares - 10,000,000; issued and outstanding shares - 200,000 presented above - - Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 210,926,742 at September 30, 2008 and 104,578,941 at December 31, 2007 211 105 Additional paid-in capital 3,063,504 1,043,645 Retained earnings (deficit) (577,087) 71,992 ------------- ------------ Total shareholders' equity 2,486,628 1,115,742 ------------- ------------ Total liabilities and shareholders' equity $ 6,015,271 $ 5,955,771 ============= ============ (1) On July 18, 2008, we converted all outstanding shares of our preferred stock into a total of approximately 105.2 million shares of our common stock. The conversion of the preferred stock had the effect of increasing the book value of shareholders' equity by approximately $2.0 billion. On July 21, 2008, we paid all accrued but unpaid dividends plus cash in lieu of fractional shares upon conversion totaling approximately $12.8 million to the holders of the converted shares of preferred stock. After July 18, 2008, dividends ceased to accrue on the preferred stock and all rights of the holders with respect to the preferred stock terminated. The conversion of all outstanding shares of preferred stock into common stock eliminated our obligation to pay quarterly cash dividends of $35.0 million, resulting in annual dividend savings of $140.0 million.

EXCO Resources, Inc. Condensed consolidated statement of operations (Unaudited) Three months ended Nine months ended September 30, September 30, -------------------- --------------------- (in thousands, except per share and share data) 2008 2007 2008 2007 --------------------------- ----------- -------- ----------- --------- Revenues and other income: Oil and natural gas $ 402,384 $228,316 $1,155,978 $610,227 Midstream 27,004 4,432 61,852 14,189 Gain (loss) on derivative financial instruments 900,313 98,252 (103,534) 80,130 Other income 1,820 2,417 5,496 7,579 ----------- -------- ----------- --------- Total revenues and other income 1,331,521 333,417 1,119,792 712,125 ----------- -------- ----------- --------- Costs and expenses: Oil and natural gas production 62,979 44,376 177,518 121,349 Midstream operating expenses 28,820 4,236 59,671 11,339 Gathering and transportation 3,672 3,387 10,503 6,662 Depreciation, depletion and amortization 126,207 109,325 346,705 265,797 Write-down of oil and natural gas properties 1,193,105 - 1,193,105 - Accretion of discount on asset retirement obligations 1,482 1,324 4,271 3,534 General and administrative 21,002 17,010 63,286 46,175 Interest 44,874 36,523 101,167 146,775 ----------- -------- ----------- --------- Total costs and expenses 1,482,141 216,181 1,956,226 601,631 ----------- -------- ----------- --------- Income (loss) before income taxes (150,620) 117,236 (836,434) 110,494 Income tax expense (benefit) (4,291) 60,774 (264,352) 58,843 ----------- -------- ----------- --------- Net income (loss) (146,329) 56,462 (572,082) 51,651 Preferred stock dividends 6,997 45,733 76,997 97,968 ----------- -------- ----------- --------- Net income (loss) available to common shareholders $ (153,326) $ 10,729 $ (649,079) $(46,317) =========== ======== =========== ========= Net income (loss) per common share: Net income (loss) per common share - basic $ (0.80) $ 0.10 $ (4.84) $ (0.44) =========== ======== =========== ========= Net income (loss) per common share - diluted $ (0.80) $ 0.10 $ (4.84) $ (0.44) =========== ======== =========== ========= Weighted average shares: Basic 191,452 104,415 134,006 104,311 =========== ======== =========== ========= Diluted 191,452 106,683 134,006 104,311 =========== ======== =========== =========

EXCO Resources, Inc. Consolidated statement of cash flows (Unaudited) Nine months ended September 30, ------------------------- (in thousands) 2008 2007 -------------------------------------------- ------------ ------------ Operating Activities: Net (loss) income $ (572,082) $ 51,651 Adjustments to reconcile net (loss) income to net cash provided by operating activities: Loss (gain) on sale of other assets 20 (653) Depreciation, depletion and amortization 346,705 265,797 Stock option compensation expense 10,842 6,728 Accretion of discount on asset retirement obligations 4,271 3,534 Write-down of oil and natural gas properties 1,193,105 - Non-cash change in fair value of derivatives (59,004) 4,821 Cash settlements of assumed derivatives 96,504 8,020 Deferred income taxes (264,657) 64,918 Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011 and discount on long-term debt 6,527 10,800 Effect of changes in: Accounts receivable (27,569) (62,522) Other current assets 570 (2,547) Accounts payable and other current liabilities 76,785 29,751 ------------ ------------ Net cash provided by operating activities 812,017 380,298 ------------ ------------ Investing Activities: Additions to oil and natural gas properties, gathering systems and equipment (741,654) (319,122) Property and midstream acquisitions (745,219) (2,194,741) Advance on pending acquisition - 1,500 Proceeds from disposition of property and equipment and other 1,736 483,811 ------------ ------------ Net cash used in investing activities (1,485,137) (2,028,552) ------------ ------------ Financing Activities: Borrowings under credit agreements 1,065,185 2,008,000 Repayments under credit agreements (476,200) (2,113,532) Borrowings under senior unsecured credit term agreement 300,000 - Settlements of derivative financial instruments with a financing element (96,504) (8,020) Proceeds from issuance of common stock 14,465 3,175 Proceeds from issuance of preferred stock - 2,000,000 Payment of preferred stock dividends (82,827) (92,134) Payments for preferred stock issuance costs - (7,501) Deferred financing costs (11,374) (17,759) ------------ ------------ Net cash provided by financing activities 712,745 1,772,229 ------------ ------------ Net increase in cash 39,625 123,975 Cash at beginning of period 55,510 22,822 ------------ ------------ Cash at end of period $ 95,135 $ 146,797 ============ ============ Supplemental Cash Flow Information: Interest paid $ 109,017 $ 154,200 ============ ============ Derivative financial instruments assumed in Vernon Acquisition $ - $ (60,015) ============ ============ Derivative financial instruments assumed in Southern Gas Acquisition $ - $ (42,204) ============ ============ Supplemental non-cash investing and financing activities: Capitalized stock compensation $ 2,263 $ 1,332 ============ ============ Capitalized interest $ 1,925 $ - ============ ============ Issuance of common stock for director services $ 120 $ - ============ ============ Value of shares received for sale of properties $ - $ 4,575 ============ ============

EXCO Resources, Inc. Consolidated EBITDA And adjusted EBITDA reconciliations and statement of cash flow data (Unaudited) Three months ended Nine months ended September 30, September 30, --------------------- ---------------------- (in thousands) 2008 2007 2008 2007 ------------------------- ----------- --------- ----------- ---------- Net income (loss) $ (146,329) $ 56,462 $ (572,082) $ 51,651 Interest expense 44,874 36,523 101,167 146,775 Income tax expense (benefit) (4,291) 60,774 (264,352) 58,843 Depreciation, depletion and amortization 126,207 109,325 346,705 265,797 ----------- --------- ----------- ---------- EBITDA(1) 20,461 263,084 (388,562) 523,066 ----------- --------- ----------- ---------- Accretion of discount on asset retirement obligations 1,482 1,324 4,271 3,534 Non-cash write-down of oil and natural gas properties 1,193,105 - 1,193,105 - Non-cash change in fair value of oil and natural gas derivative financial instruments (970,332) (52,003) (53,849) 4,821 Stock based compensation expense 4,154 2,263 10,842 6,728 ----------- --------- ----------- ---------- Adjusted EBITDA(1) $ 248,870 $214,668 $ 765,807 $ 538,149 =========== ========= =========== ========== Interest expense (2) (42,659) (36,523) (106,322) (146,775) Income tax benefit (expense) 4,291 (60,774) 264,352 (58,843) Amortization of deferred financing costs, premium on 7 1/4% senior notes due 2011 and discount on long-term debt 5,710 884 6,527 10,800 Deferred income taxes (4,413) 66,849 (264,657) 64,918 Changes in operating assets and liabilities and other 53,579 21,726 49,806 (35,971) Settlements of derivative financial instruments with a financing element 34,405 4,342 96,504 8,020 ----------- --------- ----------- ---------- Net cash provided by operating activities $ 299,783 $211,172 $ 812,017 $ 380,298 =========== ========= =========== ==========

Three months ended Nine months ended September 30, September 30, -------------------- ------------------------- (in thousands) 2008 2007 2008 2007 ----------------------- ---------- --------- ------------ ------------ Statement of cash flow data: Cash flow provided by (used in): Operating activities(2) $ 299,783 $211,172 $ 812,017 $ 380,298 Investing activities (550,979) (55,886) (1,485,137) (2,028,552) Financing activities 312,189 (61,770) 712,745 1,772,229 Other financial and operating data: EBITDA(1) 20,461 263,084 (388,562) 523,066 Adjusted EBITDA(1) 248,870 214,668 765,807 538,149 (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 write-downs of oil and natural gas properties, 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 Nine months ended September 30, % September 30, % ------------------ ----------------- 2008 2007 Change 2008 2007 Change ------------------- --------- -------- ------ -------- -------- ------ Production: Oil (Mbbls) 590 475 24% 1,643 1,176 40% Gas (Mmcf) 33,017 31,608 4% 97,687 79,591 23% Oil and natural gas (Mmcfe) 36,557 34,458 6% 107,545 86,647 24% Average sales prices (before derivative financial instrument activities): Oil (per Bbl) $ 116.03 $ 72.67 60% $ 111.66 $ 64.36 73% Gas (per Mcf) 10.11 6.13 65% 9.96 6.72 48% Total production (per Mcfe) 11.01 6.63 66% 10.75 7.04 53% Average costs (per Mcfe): Oil and natural gas operating costs $ 1.16 $ 0.87 33% $ 1.08 $ 0.94 15% Gathering and transportation costs 0.10 0.10 0% 0.10 0.08 25% Production and ad valorem taxes 0.57 0.42 36% 0.57 0.46 24% General and administrative 0.57 0.49 16% 0.59 0.53 11% Depletion 3.28 3.02 9% 3.06 2.92 5% Depreciation and amortization 0.18 0.15 20% 0.17 0.14 21%

Source: Business Wire

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