EXCO Resources, Inc. Reports Third Quarter 2009 Results

DALLAS, Nov 03, 2009 (BUSINESS WIRE) -- EXCO Resources, Inc. (NYSE: XCO) today announced its third quarter 2009 results of operations. Highlights during the quarter include: a"EUR 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.

a"EUR 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.

a"EUR 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.

a"EUR 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.

a"EUR 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.

a"EUR 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.

a"EUR 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 $ 42,004 $ 0.20 $ 44,969 $ 0.23 $ 144,173 $ 0.68 $ 94,684 $ 0.68 earnings per share 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. We currently have 2 rigs drilling vertical Marcellus wells and anticipate spudding a horizontal well in the Marcellus play late in 2009.

Mid-Continent and Permian On September 30, 2009, we announced we had entered into an agreement to sell the remainder of our assets located in the Mid-Continent region for $540 million, subject to customary closing adjustments. We expect this sale to close in November 2009.

In our Permian division, we closed several smaller divestiture transactions, including the sale of all of our producing assets in Wyoming. We expect to resume drilling operations with 1 drilling rig in our Canyon Sand field in the fourth quarter and we continue to evaluate 3-D seismic over approximately 35,000 net acres adjacent to this field where we have approximately 77,000 net acres.

Midstream Concurrent with the closing of our midstream transaction with an affiliate of BG Group, we contributed our gathering and transportation systems, excluding those located in the Vernon Field in Louisiana, to a newly formed entity, TGGT Holdings, LLC (TGGT), which is a 50/50 joint venture with BG Group.

Throughput from the TGGT transportation and gathering systems averaged 513 Mmcf per day for the third quarter 2009, up from 458 Mmcf per day in the second quarter 2009. During the quarter, TGGT completed the first of four stages of the construction of its Haynesville Header system, which will be approximately 29 miles long and strategically located near EXCO's Haynesville shale development in northwest Louisiana. The first stage of the project is expected to be operational in the fourth quarter 2009 with the system fully operational by the first quarter 2010. TGGT will have approximately 300 Mmcf per day of treating capacity during the fourth quarter 2009, expanding to more than 1.0 Bcf per day during 2010. The pipeline installation program and treating facilities construction will ensure that EXCO and other third party producers have access to multiple gas markets. In addition to the Haynesville Header system, TGGT is actively evaluating additional expansion options in the Haynesville shale area in order to provide optimal evacuation routes for EXCO and its other customers.

Financial Data Our consolidated balance sheets as of September 30, 2009 and December 31, 2008, consolidated statements of operations for the three and nine months ended September 30, 2009 and 2008 and consolidated statements of cash flows for the nine months ended September 30, 2009 and 2008 are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release which have not been previously reconciled.

EXCO will host a conference call on Wednesday, November 4, 2009 at 10:00 a.m.

(Dallas time) to discuss the contents of this release and respond to questions.

Please call [phone] for US/Canada and [phone] for International if you wish to participate and ask for the EXCO conference call ID# 33502314. 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, November 3, 2009, after market close.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., November 18, 2009. Please call [phone] and enter conference ID# 33502314 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 [phone], 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 press release, and the risk factors included in the Annual Report on Form 10-K for the year ended December 31, 2008 and our other periodic filings with the SEC.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

The SEC has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the terms "probable," "possible," "potential," "unproved," or "unbooked potential," to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers.

Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2008 available on our website at www.excoresources.com under the Investor Relations tab.

EXCO Resources, Inc. Consolidated balance sheet September 30, December 31, (in thousands) 2009 2008 (Unaudited) Assets Current assets: Cash and cash equivalents $ 55,681 $ 57,139 Restricted cash(a) 69,983 - Accounts receivable: Oil and natural gas 40,356 130,970 Joint interest 35,070 22,807 Interest and other 6,545 5,895 Inventory 28,864 42,479 Derivative financial instruments 203,641 247,614 Deferred income taxes - - Other 8,578 6,136 Total current assets 448,718 513,040 Equity investment in TGGT Holdings, LLC 216,631 - Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties 246,272 481,596 Proved developed and undeveloped oil and natural gas properties 2,200,915 3,578,344 Accumulated depletion (1,103,901 ) (936,088 ) Oil and natural gas properties, net 1,343,286 3,123,852 Gas gathering assets 188,648 485,201 Accumulated depreciation and amortization (21,885 ) (32,232 ) Gas gathering assets, net 166,763 452,969 Office and field equipment, net 30,390 25,647 Derivative financial instruments 85,943 173,003 Deferred financing costs, net 12,356 62,884 Other assets 2,653 880 Goodwill 324,756 470,077 Total assets $ 2,631,496 $ 4,822,352 (a) Restricted cash represents EXCO's share of escrow funds to be used for development of Haynesville operations pursuant to our joint development agreement with BG Group.

EXCO Resources, Inc. Consolidated balance sheet September 30, December 31, (in thousands, except per share and share data) 2009 2008 (Unaudited) Liabilities and shareholders' equity Current liabilities: Accounts payable and accrued liabilities $ 78,914 $ 172,400 Accrued interest payable 8,173 28,746 Revenues and royalties payable 79,323 108,130 Income taxes payable 1,060 160 Current portion of asset retirement obligations 16 1,830 Derivative financial instruments 13,772 11,607 Total current liabilities 181,258 322,873 Long-term debt, net of current maturities 1,689,277 3,019,738 Asset retirement obligations and other long-term liabilities 116,251 125,279 Deferred income taxes 8,661 9,371 Derivative financial instruments 24,386 12,590 Commitments and contingencies - - Shareholders' equity: Preferred stock, $0.001 par value; authorized shares - 10,000,000; - - none issued and outstanding Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 211,508,191 at September 30, 2009 and 210,968,931 at December 31, 2008 212 211 Additional paid-in capital 3,088,200 3,070,766 Accumulated deficit (2,476,749 ) (1,738,476 ) Total shareholders' equity 611,663 1,332,501 Total liabilities and shareholders' equity $ 2,631,496 $ 4,822,352 EXCO Resources, Inc. Consolidated statement of operations Three months ended Nine months ended September 30, September 30, (in thousands, except per share data) 2009 2008 2009 2008 Revenues: Oil and natural gas $ 125,493 $ 402,407 $ 443,953 $ 1,155,986 Midstream 5,375 27,004 35,330 61,852 Total revenues 130,868 429,411 479,283 1,217,838 Costs and expenses: Oil and natural gas production 43,026 63,002 144,538 177,526 Midstream operating expenses 5,411 28,820 35,580 59,671 Gathering and transportation 4,927 3,672 12,879 10,503 Depreciation, depletion and amortization 50,709 126,207 187,683 346,705 Write-down of oil and natural gas properties - 1,193,105 1,293,579 1,193,105 Gain on divestitures (460,626 ) - (460,626 ) - Accretion of discount on asset retirement obligations 1,767 1,482 5,856 4,271 General and administrative 21,647 21,002 64,682 63,286 Total costs and expenses (333,139 ) 1,437,290 1,284,171 1,855,067 Operating income (loss) 464,007 (1,007,879 ) (804,888 ) (637,229 ) Other income (expense): Interest expense (46,737 ) (44,874 ) (129,760 ) (101,167 ) Gain (loss) on derivative financial instruments 14,518 900,313 204,885 (103,534 ) Other income (expense) 47 1,820 (7,895 ) 5,496 Equity method loss in TGGT Holdings, LLC (426 ) - (426 ) - Total other income (expense) (32,598 ) 857,259 66,804 (199,205 ) Income (loss) before income taxes 431,409 (150,620 ) (738,084 ) (836,434 ) Income tax expense (benefit) (1,921 ) (4,291 ) 189 (264,352 ) Net income (loss) 433,330 (146,329 ) (738,273 ) (572,082 ) Preferred stock dividends - (6,997 ) - (76,997 ) Net income (loss) available to common shareholders $ 433,330 $ (153,326 ) $ (738,273 ) $ (649,079 ) Earnings (loss) per common share: Basic Net income (loss) available to common shareholders $ 2.05 $ (0.80 ) $ (3.50 ) $ (4.84 ) Weighted average number of common shares outstanding 211,266 191,452 211,118 134,006 Diluted Net income (loss) available to common shareholders $ 2.03 $ (0.80 ) $ (3.50 ) $ (4.84 ) Weighted average common and common equivalent shares outstanding 213,235 191,452 211,118 134,006 EXCO Resources, Inc. Consolidated statement of cash flows Nine months ended September 30, (in thousands) 2009 2008 Operating Activities: Net loss $ (738,273 ) $ (572,082 ) Adjustments to reconcile net loss to net cash provided by operating activities: Loss (gain) on sale of other assets - 20 Depreciation, depletion and amortization 187,683 346,705 Stock option compensation expense 9,863 10,842 Write-down of oil and natural gas properties 1,293,579 1,193,105 Gain on divestitures (460,626 ) - Equity method loss in TGGT Holdings, LLC 426 - Accretion of discount on asset retirement obligations 5,856 4,271 Non-cash change in fair value of derivatives 144,996 (59,004 ) Cash settlements of assumed derivatives (141,782 ) 96,504 Deferred income taxes (711 ) (264,657 ) Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011 and discount on long-term debt 44,327 6,527 Effect of changes in: Accounts receivable 66,961 (27,569 ) Other current assets (5,094 ) 570 Accounts payable and other current liabilities (57,348 ) 76,785 Net cash provided by operating activities 349,857 812,017 Investing Activities: Additions to oil and natural gas properties, gathering systems and (388,859 ) (741,654 ) equipment Property and midstream acquisitions (67,774 ) (745,219 ) Net proceeds from disposition of property and equipment and other 60,774 - Restricted cash (69,983 ) - Equity investment in TGGT Holdings, LLC (47,500 ) - Deposit on pending divestitures 14,500 - Net proceeds from disposition of oil and natural gas properties, 1,348,604 1,736 gathering systems and equipment Net cash provided by (used in) investing activities 849,762 (1,485,137 ) Financing Activities: Borrowings under credit agreements 52,949 1,065,185 Repayments under credit agreements (1,080,740 ) (476,200 ) Borrowings under senior unsecured credit term agreement - 300,000 Repayments under senior unsecured credit term agreement (300,000 ) - Proceeds from issuance of common stock 5,400 14,465 Payment of preferred stock dividends - (82,827 ) Settlements of derivative financial instruments with a financing 141,782 (96,504 ) element Deferred financing costs (20,468 ) (11,374 ) Net cash provided by (used in) financing activities (1,201,077 ) 712,745 Net increase (decrease) in cash (1,458 ) 39,625 Cash at beginning of period 57,139 55,510 Cash at end of period $ 55,681 $ 95,135 Supplemental Cash Flow Information: Interest paid $ 90,010 $ 109,017 Supplemental non-cash investing and financing activities: Capitalized stock option compensation $ 2,122 $ 2,263 Capitalized interest $ 3,937 $ 1,925 Issuance of common stock for director services $ 50 $ 120 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) 2009 2008 2009 2008 Net income (loss) $ 433,330 $ (146,329 ) $ (738,273 ) $ (572,082 ) Interest expense 46,737 44,874 129,760 101,167 Income tax expense (benefit) (1,921 ) (4,291 ) 189 (264,352 ) Depreciation, depletion and amortization 50,709 126,207 187,683 346,705 EBITDA(1) 528,855 20,461 (420,641 ) (388,562 ) Accretion of discount on asset retirement obligations 1,767 1,482 5,856 4,271 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 ) - Equity method loss in TGGT Holdings, LLC 426 - 426 - Non-cash change in fair value of oil and natural gas derivative financial instruments 99,045 (970,332 ) 149,246 (53,849 ) Stock based compensation expense 3,383 4,154 9,863 10,842 Adjusted EBITDA(1) $ 172,850 $ 248,870 $ 577,703 $ 765,807 Interest expense (2) (46,982 ) (42,659 ) (134,010 ) (106,322 ) Income tax benefit (expense) 1,921 4,291 (189 ) 264,352 Amortization of deferred financing costs, premium on 7 1/4% senior notes due 2011 and discount on long-term debt 20,560 5,710 44,327 6,527 Deferred income taxes (2,821 ) (4,413 ) (711 ) (264,657 ) Changes in operating assets and liabilities and other 28,884 53,579 4,519 49,806 Settlements of derivative financial instruments with a financing element (51,488 ) 34,405 (141,782 ) 96,504 Net cash provided by operating activities $ 122,924 $ 299,783 $ 349,857 $ 812,017 Three months ended Nine months ended September 30, September 30, (in thousands) 2009 2008 2009 2008 Statement of cash flow data: Cash flow provided by (used in): Operating activities $ 122,924 $ 299,783 $ 349,857 $ 812,017 Investing activities 1,104,159 (550,979 ) 849,762 (1,485,137 ) Financing activities (1,302,760 ) 312,189 (1,201,077 ) 712,745 Other financial and operating data: EBITDA(1) 528,855 20,461 (420,641 ) (388,562 ) Adjusted EBITDA(1) 172,850 248,870 577,703 765,807 (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, gains from divestitures, equity income or losses, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives and stock-based compensation. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, these measures are used in covenant calculations required under our revolving and term credit agreements and the indenture governing our 7 1/4 % senior notes. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to us. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company's operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures.

(2) Excludes non-cash changes in fair value of $0.2 million and $4.3 million for the three and nine months ended September 30, 2009, respectively, and $2.2 million and $5.2 million for the three and nine months ended September 30, 2008, respectively, for interest rate swaps included in GAAP interest expense.

Cash Flow Third quarter 2009 cash flow from operations before changes in working capital and settlements of derivative financial instruments with a financing element (adjusted cash flow) was $146 million, a 31% decrease from the prior year's third quarter due primarily to lower product prices. The following table reconciles cash flow from operations pursuant to GAAP to cash flow without working capital adjustments and derivative settlements with a financing element.

For the nine months ended September 30, 2009, adjusted cash flow was $487 million compared with $665 million during the prior year's nine month period, a decrease of 27% which was again due primarily to lower commodity prices.

Three months ended Nine months ended September 30, % September 30, % (in thousands) 2009 2008 change 2009 2008 change Cash flow from operations, GAAP $ 122,924 $ 299,783 $ 349,857 $ 812,017 Net change in working capital (28,884 ) (53,559 ) (4,519 ) (49,786 ) Settlements of derivative financial instruments with a financing element 51,488 (34,405 ) 141,782 (96,504 ) Cash flow from operations before changes in working capital, non-GAAP measure (1) $ 145,528 $ 211,819 -31 % $ 487,120 $ 665,727 -27 % (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.

EXCO Resources, Inc. Summary of operating data Three months ended Nine months ended September 30, % September 30, % 2009 2008 Change 2009 2008 Change Production: Oil (Mbbls) 355 590 -40 % 1,367 1,643 -17 % Natural gas (Mmcf) 29,806 33,017 -10 % 96,598 97,687 -1 % Oil and natural gas (Mmcfe) 31,936 36,557 -13 % 104,800 107,545 -3 % Average sales prices (before derivative financial instrument activities): Oil (per Bbl) $ 63.88 $ 116.03 -45 % $ 50.89 $ 111.66 -54 % Natural gas (per Mcf) 3.45 10.11 -66 % 3.88 9.96 -61 % Total production (per Mcfe) 3.93 11.01 -64 % 4.24 10.75 -61 % Average costs (per Mcfe): Oil and natural gas operating costs $ 1.01 $ 1.16 -13 % $ 1.07 $ 1.08 -1 % Production and ad valorem taxes 0.33 0.57 -42 % 0.31 0.57 -46 % Gathering and transportation costs 0.15 0.10 50 % 0.12 0.10 20 % Depletion 1.40 3.28 -57 % 1.60 3.06 -48 % Depreciation and amortization 0.19 0.18 6 % 0.19 0.17 12 % General and administrative 0.68 0.57 19 % 0.62 0.59 5 % SOURCE: EXCO Resources, Inc.

CONTACT: EXCO Resources, Inc. Douglas H. Miller, Chairman, 214-368-2084 or Stephen F. Smith, President, 214-368-2084 www.excoresources.com Copyright Business Wire 2009 -0- KEYWORD: United States

North America

Texas INDUSTRY KEYWORD: Energy

Oil/Gas SUBJECT CODE: Advisory

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