EXCO Resources, Inc. Reports Third Quarter 2009 Results

http://www.businesswire.com/news/home/20091103006763/en

DALLAS--(Business Wire)--
EXCO Resources, Inc. (NYSE: XCO) today announced its third quarter 2009 results
of operations. Highlights during the quarter include:

─ 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. 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 (800) 309-5788 for US/Canada and (404) 537-3217 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 (800)
642-1687 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 (214) 368-2084, or by visiting EXCO`s website at www.excoresources.com.
EXCO`s SEC filings and press releases can be found under the Investor Relations
tab.

We believe that it is important to communicate our expectations of future
performance to our investors.However, events may occur in the future that we are
unable to accurately predict, or over which we have no control.You are cautioned
not to place undue reliance on a forward-looking statement.When considering our
forward-looking statements, keep in mind the risk factors and other cautionary
statements in this 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 equipment (388,859 ) (741,654 )
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, gathering systems and equipment 1,348,604 1,736
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 element 141,782 (96,504 )
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 derivativefinancial 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 %

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