EXCO Resources, Inc. Reports Operating and Financial Results for the Second Quarter...

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

DALLAS--(Business Wire)--
EXCO Resources, Inc. (NYSE: XCO) today announced second quarter
2008 results.

-- Adjusted net income available to common shareholders, a
non-GAAP measure adjusting for non-cash derivative losses and
items typically not included by securities analysts in
published estimates, was $0.34 per diluted share for the
second quarter 2008 compared with an adjusted net loss of
$0.11 per share for the second quarter 2007.

-- Oil and natural gas revenues for the second quarter 2008 were
$429 million, exclusive of derivative financial instrument
activities (derivatives) and $338 million inclusive of cash
settlements on derivatives. Oil and natural gas revenues for
the prior year's quarter were $262 million before derivatives,
and $268 million including cash settlements on derivatives.

-- Oil and natural gas production for the second quarter 2008 was
36 Bcfe, or 394 Mmcfe per day comprised of 358 Mmcf per day of
natural gas and 5,989 barrels of oil per day, in line with our
expectations and approximately 2% higher than the first
quarter 2008 production of 386 Mmcfe per day. Presently our
daily average production exceeds 400 Mmcfe per day.

-- Midstream operating profit, before the effect of intercompany
eliminations, was $12 million compared with $8 million in the
prior year's quarter. Operating profit after intercompany
eliminations was $4 million for the three months ended June
30, 2008 and $1 million for the three months ended June 30,
2007.

-- 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 $263 million, approximately 26% higher that the
prior year's quarter.

-- Total capital expenditures for the second quarter 2008, which
include drilling and development, leasing, midstream projects
and corporate expenditures, were $258 million, an increase of
115% from the prior year's quarter. Drilling and development
capital expenditures totaled $136 million for the second
quarter 2008 compared with second quarter 2007 drilling and
development capital expenditures of $104 million. During the
second quarter 2008, we initiated an aggressive acreage
acquisition program in our shale plays in Haynesville/Bossier
(Haynesville) in East Texas/North Louisiana and Marcellus in
Appalachia. Leasehold expenditures were approximately $78
million in these areas during the second quarter 2008.
Including the second quarter 2008 acreage acquisitions, our
net acreage exceeds 119,800 net acres in the Haynesville shale
and approximately 395,000 net acres in the Marcellus and Huron
shale plays.

-- 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 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.

Douglas H. Miller, EXCO's Chief Executive Officer commented, "The
second quarter of 2008 continued the outstanding performance of EXCO
in terms of revenues, cash flows and adjusted earnings. In addition,
we have made substantial progress in further defining the
opportunities we have in the Haynesville, Marcellus and Huron shale
plays and enhancing our acreage position. The remainder of 2008 will
see a rapid acceleration in drilling in the shales, with both vertical
and horizontal tests planned.

"We are continuing our development efforts in our Cotton Valley
program in East Texas and North Louisiana, our shallow plays in
Appalachia, and our West Texas Canyon Sand activities. However, we
have reduced the number of wells to be drilled and completed in the
Cotton Valley and Appalachia areas to focus more time and capital on
our shale assets.

"Another very positive recent event was the conversion of our
preferred stock into common stock in mid-July. This event has doubled
our equity base and will enhance our free cash flow by $140 million
annually.

"We are optimistic about our Company's prospects for the balance
of 2008 and beyond."

For the six months ended June 30, 2008, adjusted net income
available to common shareholders was $0.45 per diluted share compared
with an adjusted net loss of $0.04 per dilutive share for the six
months ended June 30, 2007. Adjusted EBITDA for the six months ended
June 30, 2008 was $517 million compared with $323 million for the six
months ended June 30, 2007, an increase of 60%.

Equivalent production for the six months ended June 30, 2008 was
71.0 Bcfe, an increase of 36% from the prior year's six month period
equivalent production of 52.2 Bcfe. The increase in production is
primarily attributable to the 2008 period including a full six months
of volumes from our 2007 acquisitions of Vernon and Southern Gas,
while the 2007 six months contain only three months of Vernon and two
months of Southern Gas.

The average price per barrel of oil, excluding derivatives, was
$109.21 per Bbl for the six months ended June 30, 2008 compared with
$58.72 for the prior year's six month period. The average natural gas
price, excluding derivatives for the six months ended June 30, 2008
and 2007 was $9.87 and $7.10 per Mcf, respectively, an increase of
approximately 39%.

Revenues and adjusted revenues

Our second quarter 2008 adjusted revenues, a non-GAAP measure
defined as revenues which exclude the non-cash impact of our oil and
natural gas derivatives, were $367 million, an increase of $92
million, or 33% from the second quarter 2007. The increase was
primarily attributable to higher product prices, before derivatives,
which increased by 59% on a per Mcfe basis over the prior year's
quarter. Realized prices, after cash settlements on derivatives, were
$9.42 per Mcfe and $7.69 per Mcfe for the three months ended June 30,
2008 and 2007, respectively.

-0-
*T
Three months ended
June 30, %
--------------------
(in thousands, except prices) 2008 2007 change
------------------------------------------ ---------- --------- ------
Oil and natural gas revenues, before
derivative financial instruments $ 428,651 $261,552 64%
Cash settlements on derivative financial
instruments (90,380) 6,630
---------- ---------
Subtotal, revenues including cash
settlements on derivative financial
instruments 338,271 268,182 26%
Non-cash gain (loss) on oil and natural
gas derivative financial instruments (572,273) 71,267
---------- ---------
Oil and natural gas revenues (234,002) 339,449
Midstream revenues 26,956 5,211 417%
Other income 2,249 1,883 19%
---------- ---------
Total revenues and other income, GAAP (204,797) 346,543

Elimination of non-cash oil and natural
gas derivative financial instruments
activity included in GAAP revenues 572,273 (71,267)
---------- ---------
Adjusted revenues (1) $ 367,476 $275,276 33%
========== =========

Prices, excluding marketing and other
income:
------------------------------------------
Realized price per Mcfe, before derivative
financial instruments $ 11.94 $ 7.50 59%
Realized price per Mcfe, after cash
settlements on derivative financial
instruments $ 9.42 $ 7.69 22%

Six months ended
June 30, %
--------------------
(in thousands, except prices) 2008 2007 change
------------------------------------------ ---------- --------- ------
Oil and natural gas revenues, before
derivative financial instruments $ 753,594 $381,911 97%
Cash settlements on derivative financial
instruments (87,364) 38,702
---------- ---------
Subtotal, revenues including cash
settlements on derivative financial
instruments 666,230 420,613 58%
Non-cash gain (loss) on oil and natural
gas derivative financial instruments (916,483) (56,824)
---------- ---------
Oil and natural gas revenues (250,253) 363,789
Midstream revenues 34,848 9,757 257%
Other income 3,676 5,162 -29%
---------- ---------
Total revenues and other income, GAAP (211,729) 378,708

Elimination of non-cash oil and natural
gas derivative financial instruments
activity included in GAAP revenues 916,483 56,824
---------- ---------
Adjusted revenues (1) $ 704,754 $435,532 62%
========== =========

Prices, excluding marketing and other
income:
------------------------------------------
Realized price per Mcfe, before derivative
financial instruments $ 10.62 $ 7.32 45%
Realized price per Mcfe, after cash
settlements on derivative financial
instruments $ 9.39 $ 8.06 17%
*T

(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, execute our capital program and make acquisitions.

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 $232 million, or a 32%
increase from the prior year's second quarter. We utilized this cash
flow primarily to fund our development and exploitation projects and
acquire acreage in our Haynesville/Bossier and Marcellus shale plays.

-0-
*T
Three months ended Six months ended
June 30, % June 30, %
------------------- -------------------
(in thousands) 2008 2007 change 2008 2007 change
---------------- --------- --------- ------ --------- --------- ------
Cash flow from
operations,
GAAP $312,724 $136,575 $512,234 $169,126
Net change in
working capital (8,283) 42,358 3,773 57,697
Cash settlements
of assumed
derivatives (72,566) (3,678) (62,099) (3,678)

--------- --------- --------- ---------
Cash flow from
operations
before changes
in working
capital, non-
GAAP measure
(1) $231,875 $175,255 32% $453,908 $223,145 103%
========= ========= ========= =========
*T

(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 and
certain 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:

-0-
*T
Three months ended Three months ended
June 30, 2008 June 30, 2007
-------------------- -------------------

(in thousands, except per
share amounts) Amount Per share Amount Per share
----------------------------- ---------- --------- --------- ---------
Net income (loss), GAAP $(262,914) $ 82,886
Adjustments:
Non-cash mark-to-market
(gains) losses on oil and
natural gas derivative
financial instruments,
before taxes 572,273 (71,267)
Non-cash mark-to-market
(gains) losses on interest
rate derivative financial
instruments, before taxes (11,001) -
Nonrecurring financing costs,
before taxes (1) - -
Income taxes on adjustments
(2) (224,509) 28,507
---------- ---------
Total adjustments, net of
taxes 336,763 (42,760)
---------- ---------
Adjusted net income $ 73,849 $ 40,126
========== =========

Net income (loss) available
to common shareholders, GAAP
(3) $(297,914) $ (2.83) $ 31,787 $ 0.30
Adjustments shown above (3) 336,763 3.20 (42,760) (0.41)
Dilution attributable to
stock options (4) - (0.02) - n/a
---------- --------- --------- ---------
Adjusted net income (loss)
available to common
shareholders $ 38,849 $ 0.35 $(10,973) $ (0.11)
========== =========

Benefit of preferred
dividends due to assumed
conversion (5) $ 35,000 - n/a -
Adjusted net income (loss)
available to common
shareholders 38,849 - (10,973) -
---------- --------- --------- ---------
Adjusted net income (loss)
for diluted earnings per
share (5) $ 73,849 $ 0.34 $(10,973) $ (0.11)
========== ========= ========= =========

Common stock and equivalents
used for earnings per share
(EPS):
-----------------------------
Weighted average common
shares outstanding 105,253 104,313
Dilutive stock options 5,774 n/a
--------- ---------
Shares used to compute EPS
for adjusted net income
(loss) available to common
shareholders 111,027 104,313
Dilutive preferred stock 105,263 n/a
--------- ---------
Shares used to compute
diluted EPS for adjusted net
income (loss) available to
common shareholders 216,290 104,313
========= =========

Six months ended Six months ended
June 30, 2008 June 30, 2007
-------------------- -------------------

(in thousands, except per
share amounts) Amount Per share Amount Per share
----------------------------- ---------- --------- --------- ---------
Net income (loss), GAAP $(425,753) $ (4,811)
Adjustments:
Non-cash mark-to-market
(gains) losses on oil and
natural gas derivative
financial instruments,
before taxes 916,483 56,824
Non-cash mark-to-market
(gains) losses on interest
rate derivative financial
instruments, before taxes (7,370) -
Nonrecurring financing costs,
before taxes (1) - 32,100
Income taxes on adjustments
(2) (363,645) (35,570)
---------- ---------
Total adjustments, net of
taxes 545,468 53,354
---------- ---------
Adjusted net income $ 119,715 $ 48,543
========== =========

Net income (loss) available
to common shareholders, GAAP
(3) $(495,753) $ (4.72) $(57,046) $ (0.55)
Adjustments shown above (3) 545,468 5.20 53,354 0.51
Dilution attributable to
stock options (4) - (0.03) - n/a
---------- --------- --------- ---------
Adjusted net income (loss)
available to common
shareholders $ 49,715 $ 0.45 $ (3,692) $ (0.04)
========== =========

Benefit of preferred
dividends due to assumed
conversion (5) n/a - n/a -
Adjusted net income (loss)
available to common
shareholders 49,715 - (3,692) -
---------- --------- --------- ---------
Adjusted net income (loss)
for diluted earnings per
share (5) $ 49,715 $ 0.45 $ (3,692) $ (0.04)
========== ========= ========= =========

Common stock and equivalents
used for earnings per share
(EPS):
-----------------------------
Weighted average common
shares outstanding 104,968 104,258
Dilutive stock options 4,351 n/a
--------- ---------
Shares used to compute EPS
for adjusted net income
(loss) available to common
shareholders 109,319 104,258
Dilutive preferred stock n/a n/a
--------- ---------
Shares used to compute
diluted EPS for adjusted net
income (loss) available to
common shareholders 109,319 104,258
========= =========
*T

(1) See "Condensed consolidated statement of operations" for a
detailed explanation.

(2) The assumed income tax rate is 40% for all periods.

(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.

(5) Preferred stock was dilutive to adjusted net income for the
three months ended June 30, 2008. Therefore, the assumed conversion of
preferred stock and related dividend savings are included in the
diluted earnings per share computation. Diluted income per share for
the six months ended June 30, 2008 is computed using the weighted
average common stock and dilutive stock options. The assumed
conversion of preferred stock is not included in the diluted per share
computation as those shares are antidilutive for the six month period
ended June 30, 2008. The three and six months ended June 30, 2007 per
share losses are computed using only the weighted average common stock
outstanding as the stock options and assumed conversion of preferred
stock are antidilutive.

Development and Exploitation Activity

We spent $136 million on development and exploitation activities,
drilling and completing 130 gross (109.9 net) wells in the second
quarter of 2008. Our overall drilling success rate exceeded 99%. Our
total capital expenditures, including leasing, midstream and corporate
activities, totaled $258 million. We currently have 28 drilling rigs
operating across our portfolio.

As commodity prices have increased, our direct operating costs
have increased from $0.95 per Mcfe in the first quarter 2008 to $1.13
per Mcfe in the second quarter 2008. Our fuel costs have increased
approximately 40% since the start of the year and we spent $2.3
million more on workover activities in the second quarter 2008 versus
first quarter 2008.

Capital costs have increased as well. Our casing and tubular costs
have increased approximately 40% - 80% since the start of the year.
Some drilling rig day rates have increased from $18,000 per day to
$21,500 per day and some new 1,500 horsepower top-drive rigs have
increased in cost from approximately $23,500 to $27,000 per day.
However, as many of our rigs are on older long-term contracts, we have
not as yet been significantly impacted by the change in rig rates.

During the second quarter of 2008, our Board of Directors approved
a revised 2008 capital budget totaling $943 million. More than 60% of
this revised budget will be spent to drill and complete 608 gross
wells. As we have reallocated some capital originally planned for
drilling conventional, shallow Appalachian wells into shale drilling,
we have reduced our forecast number of wells to be drilled. Our plans
for the remainder of 2008 include exploiting our holdings in
Haynesville, Marcellus and Huron shale areas as well as development
drilling in all of our operating areas. The following table details
our capital budget for 2008:

-0-
*T
Drilling and
Gross wells completion Exploitation
(#) (net $ mm) (net $ mm)
----------- ------------ ------------
East Texas/North Louisiana:
Cotton Valley 141 $ 297 $ 26
Haynesville/Bossier Shale 20 32 -
Appalachia:
Conventional 229 54 4
Marcellus/Huron Shale 20 54 -
Mid-Continent 57 48 4
Permian 137 98 1
Rockies and other 4 11 -
----------- ------------ ------------
Total 608 $ 594 $ 35
=========== ============ ============

Operations
Land and other Total
(net $ mm) (net $ mm) (net $ mm) (1)
---------- ---------- --------------
East Texas/North Louisiana:
Cotton Valley $ 10 $ 58 $ 391
Haynesville/Bossier Shale 54 4 90
Appalachia:
Conventional 1 14 73
Marcellus/Huron Shale 116 - 170
Mid-Continent - 5 57
Permian 3 7 109
Rockies and other 1 3 15
---------- ---------- --------------
Total $ 185 $ 91 $ 905
========== ========== ==============
*T

(1) Does not include $19 million for information technology and
other and $19 million for Midstream.

The concentration during 2008 will include the specific activity
noted in the following areas:

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, which now exceeds
119,800 net acres. To support this increased Haynesville shale
activity, we increased our 2008 capital budget for the division to
$481 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 17
vertical and three horizontal Haynesville tests. To date, 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. To date, we have drilled four vertical wells and plan
to spud our first horizontal well in August. This 2008 activity will
add to our HBP position, continue to delineate the play and add to our
production volumes in the future. 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. Our initial production rates from these vertical well tests
have ranged from 800 to 2,800 Mcf per day at flowing pressures ranging
from 1,000 to 3,200 psi. We are continuing to refine our fracture
technologies and methodologies. We have plans for increased activity
in the Haynesville shale in 2009, and accordingly have signed
long-term commitments with drilling contractors for five 1,500
horsepower, top drive drilling rigs capable of drilling horizontal
Haynesville wells. Our first horizontal Haynesville well is scheduled
to spud in August 2008, and the remaining four rigs will be delivered
to us beginning in November and continuing through the second quarter
2009.

In addition to the 20 shale wells mentioned above, we plan to
drill 141 conventional wells in 2008 in the East Texas/North Louisiana
division. We currently have 11 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 late 2008. 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 plays
and both areas have Haynesville opportunities. In the second quarter,
we drilled and completed 42 gross (31.1 net) wells in the East
Texas/North Louisiana area with a 100% success rate.

Our Midstream operations in East Texas/North Louisiana continue to
grow from both third party and company-owned production throughput.
Current throughput is approximately 535 Mmcf per day, with
approximately 60% of the throughput from equity volumes and 40% from
third parties. We are nearing completion of our $37.6 million,
57-mile, predominantly 20-inch diameter TGG intrastate pipeline
expansion. A first phase of the expansion encompassing 20-miles of
line was available for service during the second quarter, and the
remaining 37 miles will be installed and operational prior to
year-end. This expansion will allow us to add an incremental 100 Mmcf
per day without compression to the existing throughput volumes. With
compression, incremental throughput volumes could exceed 200 Mmcf per
day. We are evaluating opportunities to expand our Midstream
operations throughout the East Texas/North Louisiana region to support
continued development of the Haynesville shale.

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 second
quarter, we drilled and completed 45 gross (41.4 net) wells in our
Appalachian division. We had one dry hole, resulting in a quarterly
success rate of 98%. We plan to drill 229 gross wells to our
conventional Appalachian targets during 2008, and we currently have
nine rigs drilling in the region.

The targeted number of wells is a reduction from the 330 well
target we previously announced, as we are reallocating resources to
our shale efforts. Significant focus and effort is directed to our
extensive Marcellus and Huron shale holdings in Pennsylvania and West
Virginia. During the second quarter, we spud two horizontal Marcellus
wells in Central Pennsylvania, three vertical Marcellus wells in West
Virginia, and one horizontal Huron shale well, also in West Virginia.
By year end, we plan to drill and complete an additional two Marcellus
horizontal wells, an additional four vertical Marcellus wells, and
approximately seven additional Huron horizontal wells, two of which we
have already begun drilling. Our first Marcellus well, which we plan
to complete during the third quarter 2008, found a shale thickness of
194 feet, with relatively high average porosity and total organic
carbon.

We hold nearly 1.1 million net leasehold acres in the Appalachian
Basin. Included in this leasehold are approximately 395,000 acres of
Marcellus potential and 121,000 acres of Huron potential. Within the
Marcellus acreage, we believe approximately 276,000 acres are in the
core, overpressured area of the play, and approximately 70% of our
acreage is held by shallow production.

While the Huron play can be developed with equipment already
present in the basin, the Marcellus play will require additional,
larger, fit-for-purpose drilling rigs to be brought into the basin.
Accordingly, we have signed long term contracts with a drilling rig
contractor to provide two 1,000 horsepower, top-drive rigs which will
be delivered to us beginning in early 2009.

Other

Our Permian Canyon Sand field development and extension work is
continuing. We drilled and completed 31 gross (30.1 net) wells in our
Permian area (all of which were in our Canyon Sand Field) in the
second quarter and achieved 100% success rate on our drilling. We plan
to drill 124 wells in the field during 2008. Of the $109 million
budgeted 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. We have acquired and are evaluating
3-D seismic data over this 11,000 acre block and plan to drill at
least two wells in this area by year-end 2008. In the second quarter
2008, we leased an additional 12,300 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 47,000 net acres.

In our Mid-Continent division, we drilled 12 gross (7.3 net) wells
during the second quarter and achieved a 100% drilling success rate.
We have budgeted to drill 57 gross wells in the region this year, and
had four rigs drilling on our acreage at the end of the second quarter
2008.

We are budgeting $57 million of capital for the Mid-Continent area
and $15 million for the Rockies and other plays in West Texas and
other areas.

Acquisitions

On July 15, 2008, we acquired natural gas properties in East Texas
(primarily in Gregg, Rusk and Upshur Counties) from private sellers
for $244 million after preliminary closing adjustments. The properties
include more than 15 Mmcfe per day of net production from 83 producing
wells, more than 500 Cotton Valley, Travis Peak and Rodessa drilling
locations, 92 of which are proved, and approximately 109 Bcfe of
proved reserves as calculated based on NYMEX strip pricing in effect
at the effective date of acquisition. The properties also include some
11,000 gross acres, a significant amount of which has deep rights. We
plan to spend $20 million of capital in this acquisition area in 2008
and drill nine wells by year-end, at least one of which will be
drilled into the Haynesville.

Liquidity

On August 1, 2008, our combined borrowing base on our revolving
credit facilities was approximately $2.5 billion, and our unused
borrowing capacity was $255.6 million.

On July 15, 2008, we entered into a $500 million senior unsecured
term credit agreement and utilized $300 million to fund the
acquisition of the East Texas properties previously discussed.

Financial Data

Our condensed consolidated balance sheets as of June 30, 2008
(unaudited) and December 31, 2007, unaudited condensed consolidated
statements of operations for the three and six months ended June 30,
2008 and 2007, and unaudited condensed consolidated statements of cash
flows for the six months ended June 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 Wednesday, August 6, 2008 at
1:30 p.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#564162851. 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 Tuesday, August 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., August 13, 2008.
Please call (800) 642-1687 and enter conference ID# 45480181 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. 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.

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*T
EXCO Resources, Inc.
Condensed consolidated balance sheets

June 30, December 31,
(in thousands) 2008 2007
------------------------------------------- ------------- ------------
(Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 34,142 $ 55,510
Accounts receivable:
Oil and natural gas 229,567 146,297
Joint interest 19,378 21,614
Interest and other 4,811 2,151
Derivative financial instruments 2,808 66,632
Deferred income taxes 209,601 6,764
Other 27,077 12,332
------------- ------------
Total current assets 527,384 311,300
------------- ------------
Oil and natural gas properties (full cost
accounting method):
Unproved oil and natural gas properties 453,680 334,803
Proved developed and undeveloped oil
and natural gas properties 5,667,619 4,926,053
Accumulated depletion (709,572) (500,493)
------------- ------------
Oil and natural gas properties, net 5,411,727 4,760,363
------------- ------------
Gas gathering assets 442,865 340,706
Accumulated depreciation and
amortization (23,794) (16,142)
------------- ------------
Gas gathering assets, net 419,071 324,564
------------- ------------
Office and field equipment, net 23,456 20,844
Advance on pending acquisition 25,206 39,500
Derivative financial instruments 4,562 2,491
Deferred financing costs, net 18,705 20,406
Other assets 1,398 6,226
Goodwill 470,077 470,077
------------- ------------
Total assets $ 6,901,586 $5,955,771
============= ============
*T

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EXCO Resources, Inc.
Condensed consolidated balance sheets

December
June 30, 31,
(in thousands, except per share and share data) 2008 2007
----------------------------------------------- ----------- ----------
(Unaudited)
Liabilities and shareholders' equity
Current liabilities:
Accounts payable and accrued liabilities $ 153,570 $ 106,305
Accrued interest payable 22,094 21,835
Revenues and royalties payable 149,145 100,978
Income taxes payable 80 87
Current portion of asset retirement
obligations 1,861 1,656
Derivative financial instruments 598,860 47,306
----------- ----------
Total current liabilities 925,610 278,167
----------- ----------
Long-term debt 2,618,013 2,099,171
Asset retirement obligations and other long-
term liabilities 105,699 89,810
Deferred income taxes 213,991 271,398
Derivative financial instruments 405,011 109,205
Commitments and contingencies - -

7.0% Cumulative Convertible Perpetual Preferred
Stock, $0.001 par value, 39,008 shares
outstanding at June 30, 2008 and December 31,
2007, liquidation preference of $391,218 388,574 388,574
Hybrid Preferred Stock, $0.001 par value,
160,992 shares outstanding at June 30, 2008
and December 31, 2007, liquidation preference
of $1,614,616 1,603,704 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 - 105,556,370 at June
30, 2008 and 104,578,941 at December 31,
2007 106 105
Additional paid-in capital 1,064,639 1,043,645
Retained earnings (deficit) (423,761) 71,992
----------- ----------
Total shareholders' equity 640,984 1,115,742
----------- ----------
Total liabilities and shareholders'
equity $6,901,586 $5,955,771
=========== ==========
*T

(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.

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EXCO Resources, Inc.
Condensed consolidated statement of operations
(Unaudited)

Three months ended Six months ended
June 30, June 30,
-------------------- ----------------------
(in thousands, except per
share data) 2008 2007 2008 2007
-------------------------- ---------- --------- ------------ ---------
Revenues and other income:
Oil and natural gas $ 428,651 $261,552 $ 753,594 $381,911
Midstream 26,956 5,211 34,848 9,757
Gain (loss) on
derivative financial
instruments (662,653) 77,897 (1,003,847) (18,122)
Other income 2,249 1,883 3,676 5,162
---------- --------- ------------ ---------
Total revenues and
other income (204,797) 346,543 (211,729) 378,708
---------- --------- ------------ ---------
Costs and expenses:
Oil and natural gas
production 62,058 47,046 114,539 76,973
Midstream operating
expenses 22,824 4,139 30,851 7,103
Gathering and
transportation 3,700 2,303 6,831 3,275
Depreciation, depletion
and amortization 111,281 105,148 220,498 156,472
Accretion of discount
on asset retirement
obligations 1,473 1,267 2,789 2,210
General and
administrative 19,657 14,990 42,284 29,165
Interest (1) 20,273 33,543 56,293 110,252
---------- --------- ------------ ---------
Total costs and
expenses 241,266 208,436 474,085 385,450
---------- --------- ------------ ---------
Income (loss) before
income taxes (446,063) 138,107 (685,814) (6,742)
Income tax expense
(benefit) (183,149) 55,221 (260,061) (1,931)
---------- --------- ------------ ---------
Net income (loss) (262,914) 82,886 (425,753) (4,811)
Preferred stock
dividends (35,000) (51,099) (70,000) (52,235)
---------- --------- ------------ ---------
Net income (loss)
available to common
shareholders $(297,914) $ 31,787 $ (495,753) $(57,046)
========== ========= ============ =========
Net income (loss) per
common share:
Net income (loss) per
common share - basic $ (2.83) $ 0.30 $ (4.72) $ (0.55)
========== ========= ============ =========
Net income (loss) per
common share - diluted $ (2.83) $ 0.30 $ (4.72) $ (0.55)
========== ========= ============ =========
Weighted average shares:
Basic 105,253 104,313 104,968 104,258
========== ========= ============ =========
Diluted 105,253 106,909 104,968 104,258
========== ========= ============ =========
*T

(1) Interest expense for the six months ended June 30, 2007
includes one time charges of $32.1 million incurred during the first
quarter 2007. Expenses associated with the payoff of the EXCO
Operating Company, LP Senior Term Credit Agreement included a $13.0
million redemption premium, a $9.2 million write-off of deferred
financing costs, and a $3.0 million write-off of unamortized original
issue discount. In addition, $6.9 million of commitment fees were
expensed in connection with other debt arrangements that were
terminated in the first quarter of 2007. Interest expense for the
three and six months ended June 30, 2008 includes decreases to
interest expense of $11.0 million and $7.4 million, respectively, a
result of non-cash gains resulting from interest rate swaps entered
into during the first quarter 2008.

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EXCO Resources, Inc.
Consolidated statement of cash flows
(Unaudited)

Six months ended
June 30,
-----------------------
(in thousands) 2008 2007
---------------------------------------------- ---------- ------------
Operating Activities:
Net loss $(425,753) $ (4,811)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depreciation, depletion and amortization 220,498 156,472
Stock option compensation expense 6,688 4,465
Accretion of discount on asset retirement
obligations 2,789 2,210
Non-cash change in fair value of
derivatives 909,111 56,824
Cash settlements of assumed derivatives 62,099 3,678
Deferred income taxes (260,244) (1,931)
Amortization of deferred financing costs
and premium on 7 1/4% senior notes due
2011 and discount on long-term debt 817 9,916
Effect of changes in:
Accounts receivable (83,688) (91,091)
Other current assets (13,829) (755)
Accounts payable and other current
liabilities 93,746 34,149
---------- ------------
Net cash provided by operating activities 512,234 169,126
---------- ------------
Investing Activities:
Additions to oil and natural gas properties,
gathering systems and equipment (910,485) (2,353,707)
Advance on pending acquisition (25,205) 5,000
Proceeds from disposition of property and
equipment and other 1,532 376,041
---------- ------------
Net cash used in investing activities (934,158) (1,972,666)
---------- ------------
Financing Activities:
Borrowings under credit agreements 812,200 1,928,000
Repayments under credit agreements (291,700) (2,023,532)
Settlements of derivative financial
instruments with a financing element (62,099) (3,678)
Proceeds from issuance of common stock 12,929 2,228
Proceeds from issuance of preferred stock - 2,000,000
Payment of preferred stock dividends (70,000) (43,717)
Payments for preferred stock issuance costs - (7,498)
Deferred financing costs (774) (17,804)
---------- ------------
Net cash provided by financing activities 400,556 1,833,999
---------- ------------
Net increase (decrease) in cash (21,368) 30,459
Cash at beginning of period 55,510 22,822
---------- ------------
Cash at end of period $ 34,142 $ 53,281
========== ============

Supplemental Cash Flow Information:
Interest paid $ 63,651 $ 108,662
========== ============
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 $ 1,276 $ 882
========== ============
Capitalized interest $ 316 $ -
========== ============
Issuance of common stock for director
services $ 102 $ -
========== ============
Value of shares received for sale of
properties $ - $ 3,431
========== ============
*T

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EXCO Resources, Inc.
Consolidated EBITDA
And adjusted EBITDA reconciliations and statement of cash flow data
(Unaudited)

Three months ended Six months ended
June 30, June 30,
-------------------- ---------------------
(in thousands) 2008 2007 2008 2007
--------------------------- ---------- --------- ---------- ----------

Net income (loss) $(262,914) $ 82,886 $(425,753) $ (4,811)
Interest expense 20,273 33,543 56,293 110,252
Income tax expense
(benefit) (183,149) 55,221 (260,061) (1,931)
Depreciation, depletion
and amortization 111,281 105,148 220,498 156,472
-------------------- ---------- ----------
EBITDA(1) (314,509) 276,798 (409,023) 259,982
Accretion of discount on
asset retirement
obligations 1,473 1,267 2,789 2,210
Non-cash change in fair
value of oil and
natural gas derivative
financial instruments 572,273 (71,267) 916,483 56,824
Stock-based compensation
expense 3,684 2,554 6,688 4,465
---------- --------- ---------- ----------
Adjusted EBITDA(1) $ 262,921 $209,352 $ 516,937 $ 323,481
========== ========= ========== ==========
Interest expense (2) (31,274) (33,543) (63,663) (110,252)
Income tax benefit
(expense) 183,149 (55,221) 260,061 1,931
Amortization of deferred
financing costs,
premium on 7 1/4%
senior notes due 2011
and discount on long-
term debt 411 561 817 9,916
Deferred income taxes (183,332) 54,106 (260,244) (1,931)
Changes in operating
assets and liabilities
and other 8,283 (42,358) (3,773) (57,697)
Settlements of
derivative financial
instruments with a
financing element 72,566 3,678 62,099 3,678
---------- --------- ---------- ----------
Net cash provided by
operating activities $ 312,724 $136,575 $ 512,234 $ 169,126
========== ========= ========== ==========
*T

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*T

Three months ended Six months ended
June 30, June 30,
--------------------- -----------------------
(in thousands) 2008 2007 2008 2007
----------------------- ---------- ---------- ---------- ------------

Statement of cash flow
data:
Cash flow provided by
(used in):
Operating
activities(2) $ 312,724 $ 136,575 $ 512,234 $ 169,126
Investing activities (329,289) (571,310) (934,158) (1,972,666)
Financing activities 41,594 318,338 400,556 1,833,999
Other financial and
operating data:
EBITDA(1) (314,509) 276,798 (409,023) 259,982
Adjusted EBITDA(1) 262,921 209,352 516,937 323,481
*T

(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
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.

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EXCO Resources, Inc.
Summary of operating data

Three months Six months
ended ended
June 30, % June 30, %
--------------- ---------------
2008 2007 Change 2008 2007 Change
---------------------- ------- ------- ------ ------- ------- ------

Production:
Oil (Mbbls) 545 426 28% 1,053 701 50%
Gas (Mmcf) 32,621 32,320 1% 64,670 47,983 35%
Oil and natural gas
(Mmcfe) 35,891 34,876 3% 70,988 52,189 36%

Average sales prices
(before derivative
financial instrument
activities):
Oil (per Bbl) $121.07 $ 61.17 98% $109.21 $ 58.72 86%
Gas (per Mcf) 11.12 7.29 53% 9.87 7.10 39%
Total production (per
Mcfe) 11.94 7.50 59% 10.62 7.32 45%

Average costs (per
Mcfe):
Oil and natural gas
operating costs $ 1.13 $ 0.86 31% $ 1.04 $ 0.99 5%
Gathering and
transportation costs 0.10 0.07 43% 0.10 0.06 67%
Production and ad
valorem taxes 0.60 0.49 22% 0.57 0.49 16%
General and
administrative 0.55 0.43 28% 0.60 0.56 7%
Depletion 2.93 2.89 1% 2.95 2.86 3%
Depreciation and
amortization 0.17 0.13 31% 0.16 0.14 14%
*T

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

Copyright Business Wire 2008