Watch Live

Tweet TWEET

EXCO Resources, Inc. Reports Second Quarter 2013 Results

  EXCO Resources, Inc. Reports Second Quarter 2013 Results

Business Wire

DALLAS -- August 5, 2013

EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced second quarter
results for 2013.

  *Adjusted net income, a non-GAAP measure, was $0.10 per diluted share for
    the second quarter 2013 compared with $0.05 per diluted share for the
    second quarter 2012. The non-GAAP adjustments include gains from asset
    sales, non-cash gains or losses from derivative financial instruments
    (derivatives), non-cash ceiling test write-downs and other items typically
    not included by securities analysts in published estimates.
  *Adjusted EBITDA for the second quarter 2013 was $90 million compared with
    $112 million for the second quarter 2012. Adjusted EBITDA is a non-GAAP
    measure and is computed using earnings before interest, taxes, depletion,
    depreciation and amortization, and is further adjusted using gains from
    asset sales, ceiling test write-downs and other non-cash income and
    expense items.
  *GAAP results were net income of $86 million, or $0.40 per diluted share,
    for the second quarter 2013 compared with a net loss of $496 million, or
    $2.32 per diluted share, for the second quarter 2012. The second quarter
    2012 net loss included a $429 million pre-tax non-cash ceiling test
    write-down of oil and natural gas properties.
  *Oil, natural gas and natural gas liquids (NGL) production was 38 Bcfe, or
    420 Mmcfe per day, for the second quarter 2013 compared with 50 Bcfe, or
    550 Mmcfe per day in the second quarter 2012. The second quarter 2013
    production from the East Texas/North Louisiana region was 328 Mmcfe per
    day compared with 483 Mmcfe per day in the second quarter 2012. The
    decrease in production was primarily the result of the contribution of
    conventional properties to the EXCO/HGI Partnership and normal production
    declines. The second quarter 2013 production in the Appalachia region was
    64 Mmcfe per day compared with 41 Mmcfe per day in the second quarter
    2012. The increase in production was due to our focus on completion
    activities in the Marcellus shale which resulted in 32 additional wells
    coming on line subsequent to the second quarter 2012. Our proportionate
    share of production from the EXCO/HGI Partnership was 28 Mmcfe per day in
    the second quarter 2013.
  *Oil, natural gas and NGL revenues, before cash settlements on derivatives,
    for the second quarter 2013 were $150 million compared with second quarter
    2012 revenues of $118 million. Our average sales price per Mcfe increased
    to $3.93 per Mcfe for the second quarter 2013 from $2.36 per Mcfe for the
    second quarter 2012. When the impacts of cash settlements from derivatives
    are considered, oil, natural gas and NGL revenues were $151 million, or
    $3.95 per Mcfe in the second quarter 2013, compared with $180 million, or
    $3.60 per Mcfe in the second quarter 2012.
  *Our direct operating costs were $0.31 per Mcfe for the second quarter 2013
    compared with $0.38 per Mcfe for the second quarter 2012. We continue to
    focus on reducing our operating costs. Our second quarter 2013 operating
    costs per Mcfe were favorably impacted by the contribution of certain
    conventional properties to EXCO/HGI Partnership in the first quarter 2013.
    The conventional assets have higher operating costs than our shale assets.
  *Our 50% share of TGGT's adjusted net income for the second quarter 2013
    was $12 million compared with $16 million for the second quarter 2012. Our
    50% share of TGGT's adjusted EBITDA was $18 million for the second quarter
    2013 compared with $21 million for the second quarter 2012, after
    adjustments for certain non-cash items.
  *On February14, 2013, we formed the EXCO/HGI Partnership and contributed
    our conventional non-shale assets in East Texas and North Louisiana and
    our shallow Canyon Sand and other assets in the Permian Basin of West
    Texas. We received net proceeds of $575 million, after final purchase
    price adjustments, and a 25.5% economic interest in the partnership. The
    partnership also purchased certain shallow conventional assets from BG
    Group, plc (BG Group) for $131 million, after preliminary purchase price
    adjustments. The pro forma operating and financial information for the
    three and six months ended June30, 2013 and 2012 is presented as if these
    transactions occurred on January 1, 2012 in a supplemental schedule to
    this press release.
  *On July 2, 2013, we entered into definitive agreements with subsidiaries
    of Chesapeake Energy Corporation (Chesapeake) to acquire producing and
    undeveloped oil and natural gas assets in the Eagle Ford and Haynesville
    shale formations for an aggregate purchase price of approximately $1
    billion, subject to customary purchase price adjustments. We closed the
    acquisition of the Haynesville assets on July 12, 2013 for $288 million,
    after customary preliminary purchase price adjustments, with an effective
    date of January 1, 2013. We closed the acquisition of the Eagle Ford
    assets on July 31, 2013 for $685 million, after customary preliminary
    purchase price adjustments, with an effective date of April 1, 2013. To
    facilitate the purchase of these assets, we amended our credit agreement
    which has an initial borrowing base of $1.6 billion including a $400
    million asset sale requirement and a $300 million term loan. The asset
    sale requirement requires mandatory payments from proceeds of asset sales
    and must be repaid or refinanced within one year.

In connection with the closing of the Eagle Ford assets, we entered into a
participation agreement with affiliates of Kohlberg Kravis Roberts & Co. L.P.
(KKR) to sell an undivided 50% interest in the undeveloped acreage we acquired
for $131 million in cash, after preliminary purchase price adjustments. After
giving effect to the acquisition and the KKR payment, the credit agreement's
initial borrowing base and the $400 million asset sale requirement were
reduced by $131 million. We will jointly develop the Eagle Ford acreage with
KKR under the participation agreement. Details of the acquisitions and terms
of the KKR agreement are presented in the "Recent developments" section of
this press release.

Douglas H. Miller, EXCO's Chief Executive Officer, commented, “We are
executing on our strategy of acquiring assets in both our existing core areas
and strategic new plays. Our recently announced acquisition in the Haynesville
shale fortifies our leading position in that area. Our acquisition in the
Eagle Ford in South Texas diversifies our portfolio by adding significant oil
volumes with upside drilling opportunities. These acquisitions have
significant levels of production which enhance our cash flow and borrowing
base capacity. We have partnered with KKR to facilitate the drilling and
development of approximately 300 undeveloped locations in the Eagle Ford
acquisition which helps us prudently manage our capital expenditures and build
long-term value for our shareholders.”

Adjusted net income

Our reported net income (loss) shown below, a GAAP measure, includes certain
items not typically included by securities analysts in their published
estimates of financial results. The following table provides a reconciliation
of our net income (loss) to the non-GAAP measure of adjusted net income:

                Three Months Ended                                  Six Months Ended
                 June 30, 2013            June 30, 2012              June 30, 2013             June 30, 2012
(in thousands,
except per       Amount       Per share   Amount        Per share   Amount        Per share   Amount        Per share
share amounts)
Net income       $ 85,598                  $ (496,433 )               $ 243,718                  $ (778,082 )
(loss), GAAP
Adjustments:
Non-cash
mark-to-market
(gains) losses     (54,452 )                 77,073                     5,779                      73,353
on derivative
financial
instruments
Non-cash write
down of oil        —                         428,801                    10,707                     704,665
and natural
gas properties
Adjustments
included in        655                       —                          369                        18,799
equity
(income) loss
(Gain) loss on
divestitures
and other          3,041                     6,673                      (181,345 )                 8,625
non-recurring
operating
items
Deferred
finance cost       —                         3,000                      3,535                      3,000
amortization
acceleration
Income taxes
on above           20,302                    (206,219 )                 64,382                     (323,377 )
adjustments
(1)
Adjustment to
deferred tax
asset             (34,239 )                198,573                  (97,487  )                311,233  
valuation
allowance (2)
Total
adjustments,      (64,693 )                507,901                  (194,060 )                796,298  
net of taxes
Adjusted net     $ 20,905                 $ 11,468                  $ 49,658                  $ 18,216   
income
                                                                                                                
Net income
(loss), GAAP     $ 85,598      $ 0.40      $ (496,433 )   $ (2.32 )   $ 243,718      $ 1.13      $ (778,082 )   $ (3.63 )
(3)
Adjustments
shown above        (64,693 )     (0.30 )     507,901        2.37        (194,060 )     (0.90 )     796,298        3.72
(3)
Dilution
attributable      —           —         —            —         —            —         —            —     
to share-based
payments (4)
Adjusted net     $ 20,905     $ 0.10     $ 11,468      $ 0.05     $ 49,658      $ 0.23     $ 18,216      $ 0.09  
income
                                                                                                                
Common stock
and
equivalents
used for
earnings per
share (EPS):
Weighted
average common     214,788                   214,164                    214,786                    214,154
shares
outstanding
Dilutive stock     437                       —                          —                          —
options
Dilutive
restricted        798                     —                        561                      —        
shares
Shares used to
compute
diluted EPS       216,023                 214,164                  215,347                  214,154  
for adjusted
net income
                                                                                                                

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

(2) Deferred tax valuation allowance has been adjusted to reflect the assumed
income tax rate of 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 share equivalents
from in-the-money stock options and dilutive restricted shares calculated in
accordance with the treasury stock method.

Cash flow

Our cash flow from operations before changes in working capital and
non-recurring other operating items was $77 million for the second quarter
2013. We primarily use our cash flow from operations and available borrowing
capacity in our credit agreement to fund our drilling and development programs
and acquire producing properties. For the six months ended June 30, 2013, our
cash flows from operations before changes in working capital and non-recurring
items exceeded our capital expenditures by approximately $25 million.

                                                  
                         Three Months Ended          Six Months Ended
                         June 30,                    June 30,
(in thousands)            2013       2012        2013       2012    
Cash flow from           $ 128,019     $ 135,345     $ 171,232     $ 280,468
operations, GAAP
Net change in working      (53,585 )     (45,355 )     (18,595 )     (96,934 )
capital
Non-recurring other       2,353       6,673       5,005       8,625   
operating items
Cash flow from
operations before
changes in working
capital and              $ 76,787     $ 96,663     $ 157,642    $ 192,159 
non-recurring other
operating items,
non-GAAP measure (1)
                                                                             

(1) Cash flow from operations before working capital changes and non-recurring
other operating items are 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. Cash flow from operations before changes in working
capital 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. Non-recurring other operating items have been excluded
as they do not reflect our on-going operating activities.

Recent developments

Haynesville shale acquisition

We closed the acquisition of the Haynesville assets from Chesapeake on July
12, 2013 for a purchase price of $288 million, after customary preliminary
purchase price adjustments. The acquisition included certain producing and
undeveloped oil and natural gas assets located in our core Haynesville shale
operating area in Caddo Parish and DeSoto Parish, Louisiana. These properties
included Chesapeake's non-operated interests in 170 wells operated by EXCO on
approximately 5,600 net acres, and operated interests in 11 producing wells on
approximately 4,000 net acres. The acquisition added approximately 55
identified drilling locations in the Haynesville shale formation to our
drilling inventory. The Haynesville transaction provides strong base
production and additional drilling inventory with upside development
opportunities. Our internally generated engineered proved reserves, utilizing
NYMEX strip prices and the January 1, 2013 effective date of the acquisition,
are estimated to be 365 Bcfe. Recent net production from the properties
averaged 114 Mmcfe per day. These assets are subject to BG Group's
preferential right to acquire a 50% interest, which was formally offered to BG
Group on July 13, 2013. Their election must be made within 60 days of our
offer. If BG Group elects to participate, the proceeds, net of any applicable
borrowing base assigned to the properties, will be used to reduce the bridge
loan tranche of our credit agreement. Our development plans are to run up to
three additional drilling rigs in manufacturing mode on recently acquired
drilling locations by the end of 2013.

Eagle Ford shale acquisition

We closed the acquisition of the Eagle Ford assets from Chesapeake on July 31,
2013, for a purchase price of $685 million, after customary preliminary
purchase price adjustments. The acquisition included certain producing and
undeveloped oil and natural gas assets in the Eagle Ford shale in the counties
of Zavala, Dimmit, La Salle and Frio in South Texas. These properties include
operated interests in 120 wells on approximately 55,000 net acres. The
acquisition added approximately 300 identified drilling locations to our
drilling inventory. In addition, we entered into a farm-out agreement with
Chesapeake covering an additional 147,000 net acres adjacent to the acquired
properties. Pursuant to the terms of the farm-out agreement, Chesapeake
retains an overriding royalty interest in wells drilled on acreage covered by
the farm-out agreement, with an option to convert the overriding royalty
interest to a working interest at payout of the well. Our internally generated
engineered proved reserves, utilizing NYMEX strip prices and the April 1, 2013
effective date of the acquisition, are estimated to be 29 Mmboe, with
potential for 92 Mmboe with the development of the acquired assets. Recent net
production from these properties averaged 6,100 Boe per day (85% oil). We also
believe that additional upside exists in deeper formations such as the Buda
and Pearsall, as well as shallow targets in the Austin Chalk and additional
formations up hole.

KKR Participation Agreement

In connection with closing the Eagle Ford assets transaction, we entered into
a participation agreement with KKR (KKR Participation Agreement) and sold an
undivided 50% interest in the undeveloped acreage we acquired for
approximately $131 million, after preliminary closing adjustments.

The KKR Participation Agreement provides that EXCO and KKR will jointly fund
future development costs. With respect to each well drilled, EXCO will assign
half of its undivided 50% interest in such well to KKR such that KKR will fund
and own 75% of each well drilled and EXCO will fund and own 25% of each well
drilled. When each quarterly tranche of wells drilled has been on production
for one year, EXCO is required to offer to purchase KKR's 75% working interest
at fair market value as defined in the KKR Participation Agreement, subject to
specific well criteria and return hurdles. With respect to the first year
(first four quarters) of the development program, we are required to make our
first offer during the fourth quarter of 2014 for wells that have been online
for approximately one year.

There are currently three rigs drilling on the acquired Eagle Ford properties
and our development plans for the remainder of 2013 include adding up to two
more rigs. The development program will consist of manufacturing mode
drilling, acreage retention focused drilling and pilot spacing drilling to
test spacing between laterals. We expect to realize significant operational
efficiencies by moving to a manufacturing mode development program in the
play. With KKR, we expect to drill approximately 300 identified locations over
a five-year period including 30 wells during 2013.

Operations activity and outlook

We spent $49 million on development and exploitation activities, drilling and
completing 18 gross (6.5 net) operated wells in the three months ended June
30, 2013. In addition, we participated in 3 gross (0.2 net) wells operated by
others (OBO) during the second quarter 2013. We had an overall drilling
success rate of 100% for the second quarter 2013.

Our actual capital expenditures for the six months ended June30, 2013 are
presented in the following table:

(in thousands)                     Q1 2013   Q2 2013   YTD 2013
Capital expenditures (1):
Development capital                 $ 58,715   $ 48,963   $ 107,678
Gas gathering and water pipelines     —          —          —
Lease acquisitions and seismic        —          2,449      2,449
Capitalized interest                  5,038      4,779      9,817
Corporate and other                  4,596     4,310     8,906
Total                               $ 68,349   $ 60,501   $ 128,850
                                                            

(1) Excludes capital expenditures related to our partnership with HGI.

Our capital budget for the remainder of 2013 will be significantly impacted by
the acquisitions of assets in the Eagle Ford and Haynesville shale formations.
Management is currently finalizing our development plans and related capital
expenditures for the remainder of 2013 as a result of these acquisitions.

Haynesville/Bossier Shale

As of June 30, 2013, our Haynesville/Bossier shale operated production was 971
Mmcf per day gross (283 Mmcf per day net) and with the addition of production
from our OBO wells, we had 302 Mmcf per day of total net Haynesville/Bossier
shale production. We operated three drilling rigs in the play during the
second quarter 2013. We currently have 39 units fully developed in the
Haynesville in DeSoto Parish. Including the 11 sections acquired from
Chesapeake, we have an additional 40 units to be developed in our core DeSoto
Parish area. We completed and turned to sales 15 gross (5.0 net) operated
Haynesville horizontal wells in the quarter. We spud seven operated horizontal
wells and participated in three OBO wells during the quarter. In total, we
have 411 operated horizontal wells and 181 OBO horizontal wells flowing to
sales.

Excluding the recently acquired drilling locations from Chesapeake, we plan to
drill 26 gross (15.5 net) operated wells with our three-rig program for the
full year 2013. Including completions carried into 2013 from wells drilled in
late 2012, we plan to complete and turn to sales 42 gross (22.1 net) wells for
the full year 2013. The drilling and completion activities on the recently
acquired sections from Chesapeake are subject to a number of factors,
including BG Group's election to participate in the acquisition and agreement
on a related drilling program.

The average initial production rate from the 15 operated Haynesville
horizontal wells completed and turned to sales in the second quarter 2013 in
DeSoto Parish was 12,090 Mmcf per day with an average 7,389 psi flowing casing
pressure on an average 18/64ths choke. This maximum choke size is indicative
of our modified restricted choke management program in DeSoto Parish.

Our cost reduction and efficiency program is delivering positive results. We
continue to see improvements in drilling times, stimulation costs and overall
capital efficiency. Our current DeSoto Parish well costs are averaging
approximately $7.7 million per well.

Marcellus Shale

Our gross operated Marcellus shale production at the end of the second quarter
2013 was 169 Mmcf per day (49 Mmcf per day net). Our focus through 2013 has
been to complete and turn to sales our remaining drilled well inventory while
reducing the size of our drilling program due to low natural gas prices. In
the second quarter 2013, we spud two development wells in Central Pennsylvania
and completed three gross operated (1.5 net) Marcellus wells in Central and
Northeast Pennsylvania. During the remainder of 2013, we plan to turn to sales
an additional 9 gross (3.2 net) Marcellus wells, two in our Central
Pennsylvania area and seven in Northeast Pennsylvania. Our development
planning for 2014 is underway and will be a combination of development
drilling in our highest rate of return areas and selective appraisal drilling
to delineate more of our acreage base.

In addition to the Marcellus shale production in Appalachia, we averaged 33
gross (14 net) operated Mmcfe per day of conventional production in the
region.

EXCO/HGI Partnership

The following discussion of operating results, capital expenditures and
planned operations addresses the EXCO/HGI Partnership in which we own a 25.5%
economic interest.

Permian

During the second quarter 2013, the partnership drilled and completed 8 gross
(7.9 net) wells in the Sugg Ranch area with 100% drilling success.
Additionally, there was 1 gross (0.3 net) well successfully drilled in the
Ackerly area in Dawson County. Economics for this drilling activity typically
have high rates-of-return driven by oil and NGL content. The partnership
expects to run one operated rig intermittently at Sugg Ranch for the remainder
of 2013. At the end of the second quarter 2013, production from the 451
partnership wells averaged approximately 3,650 net Boe per day. This average
production rate consisted of 1,240 net barrels of oil, 6,500 net Mcf of
natural gas, and 1,320 net barrels of natural gas liquids per day.

East Texas/North Louisiana

The Vernon Field in Jackson Parish, Louisiana is the most significant
producing field in this group of assets. At the end of the second quarter, net
operated production averaged approximately 43 Mmcfe per day from the lower
Cotton Valley and Bossier Sand formations. With current low commodity prices,
the primary focus in the Vernon Field is to minimize our operating expense
while maintaining production.

At the end of the second quarter, net operated production from other fields in
East Texas/ North Louisiana averaged approximately 39 Mmcfe per day. Capital
spending during the quarter was focused on maintaining our base production
performance and on the recompletion of five wells in the Holly and Kingston
fields with the addition of Cotton Valley and Hosston sands. During the
remainder of the year, we will continue our recompletion program working on
four additional wells.

In East Texas/North Louisiana, the EXCO/HGI Partnership currently has 915
wells flowing to sales with a total gross operated production rate of
approximately 120 Mmcfe per day (82 Mmcfe per day net). In addition, net
production from OBO wells averaged 2 Mmcfe per day.

TGGT

TGGT’s average throughput was approximately 1.3 Bcf per day during the second
quarter 2013, compared with 1.5 Bcf per day in the second quarter 2012. TGGT's
capital spending for the second quarter 2013 was $8 million. Capital spending
has transitioned from major facility and pipeline projects to primarily
installation of field infrastructure pipelines to support producer drilling
activity in North Louisiana and East Texas.

Financial Data

Our consolidated balance sheets as of June30, 2013 and December31, 2012,
consolidated statements of operations for the three and six months ended
June30, 2013 and 2012 and consolidated statements of cash flows for the six
months ended June30, 2013 and 2012, are included on the following pages. We
have also included reconciliations of non-GAAP financial measures referred to
in this press release.

EXCO will host a conference call on Tuesday, August 6, 2013 at 9:00 a.m.
(Central 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#14766051. 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, after market
close, on EXCO’s website on Monday, August 5, 2013.

A digital recording will be available starting two hours after the completion
of the conference call until August 20, 2013. Please call (800) 585-8367 and
enter conference ID#14766051 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 Chris Peracchi, EXCO’s Director of Finance and Investor Relations
and Treasurer 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. We caution
users of the financial statements not to place undue reliance on a
forward-looking statement. When considering our forward-looking statements,
keep in mind the cautionary statements and the risk factors included in our
Annual Report on Form10-K for the year ended December31, 2012, filed with
the Securities and Exchange Commission, or the SEC, on February21, 2013 and
our other periodic filings with the SEC.

Our revenues, operating results and financial condition substantially depend
on prevailing prices for oil and natural gas and the availability of capital
from our credit agreement, or the EXCO Resources Credit Agreement. Declines in
oil or natural gas prices may have a material adverse effect on our financial
condition, liquidity, results of operations, the amount of oil or natural gas
that we can produce economically and the ability to fund our operations.
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 permits oil and natural gas companies in filings made with the SEC to
disclose 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. The SEC permits optional
disclosure of “probable” and “possible” reserves in filings with the
commission. EXCO may use broader terms to describe additional reserve
opportunities such as “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, probable or possible reserves and
accordingly are subject to substantially greater risk of actually being
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, 2012, which is available on our website at www.excoresources.com under the
Investor Relations tab.

                                                             
EXCO Resources, Inc.
Consolidated Balance Sheets
                                                                
(in thousands)                                 June 30,         December 31,
                                               2013             2012
                                               (Unaudited)
Assets
Current assets:
Cash and cash equivalents                      $ 80,442         $ 45,644
Restricted cash                                  42,542           70,085
Accounts receivable, net:
Oil and natural gas                              78,029           84,348
Joint interest                                   62,519           69,446
Other                                            18,209           15,053
Inventory                                        4,727            5,705
Derivative financial instruments                 33,082           49,500
Other                                           16,767         22,085     
Total current assets                            336,317        361,866    
Equity investments                               371,190          347,008
Oil and natural gas properties (full cost
accounting method):
Unproved oil and natural gas properties and      367,407          470,043
development costs not being amortized
Proved developed and undeveloped oil and         2,699,608        2,715,767
natural gas properties
Accumulated depletion                           (2,029,922 )    (1,945,565 )
Oil and natural gas properties, net             1,037,093      1,240,245  
Gas gathering assets                             33,562           130,830
Accumulated depreciation and amortization       (9,688     )    (34,364    )
Gas gathering assets, net                       23,874         96,466     
Office, field and other equipment, net           17,597           20,725
Deferred financing costs, net                    18,098           22,584
Derivative financial instruments                 13,562           16,554
Goodwill                                         163,155          218,256
Other assets                                    28             28         
Total assets                                   $ 1,980,914     $ 2,323,732  

                                                             
EXCO Resources, Inc.
Consolidated Balance Sheets
                                                                
(in thousands, except per share and share      June 30,         December 31,
data)                                          2013             2012
                                               (Unaudited)      
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities       $ 81,134         $ 83,240
Revenues and royalties payable                   131,519          134,066
Accrued interest payable                         17,311           17,029
Current portion of asset retirement              395              1,200
obligations
Income taxes payable                             —                —
Derivative financial instruments                3,186          2,396      
Total current liabilities                       233,545        237,931    
Long-term debt                                   1,310,407        1,848,972
Deferred income taxes                            —                —
Derivative financial instruments                 13,335           26,369
Asset retirement obligations and other           42,745           61,067
long-term liabilities
Commitments and contingencies                    —                —
Shareholders’ equity:
Preferred stock, $0.001 par value;
10,000,000 authorized shares; none issued        —                —
and outstanding
Common stock, $0.001 par value; 350,000,000
authorized shares; 217,906,792 shares issued
and 217,367,571 shares outstanding at June       215              215
30, 2013; 218,126,071 shares issued and
217,586,850 shares outstanding at December
31, 2012
Additional paid-in capital                       3,209,517        3,200,067
Accumulated deficit                              (2,821,371 )     (3,043,410 )
Treasury stock, at cost; 539,221 shares at      (7,479     )    (7,479     )
June 30, 2013 and December 31, 2012
Total shareholders’ equity                      380,882        149,393    
Total liabilities and shareholders’ equity     $ 1,980,914     $ 2,323,732  

                                               
EXCO Resources, Inc.
Consolidated Statements of Operations
(Unaudited)
                                                  
                    Three Months Ended June 30,   Six Months Ended June 30,
(in thousands,
except per share      2013       2012         2013        2012      
data)
Revenues:
Oil and natural     $  150,332     $ 117,978      $ 288,555      $ 252,826
gas
Costs and
expenses:
Oil and natural
gas operating          11,902        18,863         25,519         41,659
costs
Production and ad      3,981         6,789          9,229          13,982
valorem taxes
Gathering and          23,408        25,913         47,884         52,336
transportation
Depletion,
depreciation and       47,388        87,337         88,696         176,919
amortization
Write-down of oil
and natural gas        —             428,801        10,707         704,665
properties
Accretion of
discount on asset      556           964            1,246          1,911
retirement
obligations
General and            26,574        18,637         44,558         40,142
administrative
(Gain) loss on
divestitures and      2,640       6,710        (182,242 )    8,335     
other operating
items
Total costs and       116,449     594,014      45,597       1,039,949 
expenses
Operating income       33,883        (476,036 )     242,958        (787,123  )
(loss)
Other income
(expense):
Interest expense       (15,105 )     (20,369  )     (35,297  )     (37,133   )
Gain (loss) on
derivative             55,246        (15,258  )     11,732         38,607
financial
instruments
Other income           158           197            246            440
Equity income         11,416      15,033       24,079       7,127     
Total other           51,715      (20,397  )    760          9,041     
income (expense)
Income (loss)
before income          85,598        (496,433 )     243,718        (778,082  )
taxes
Income tax            —           —            —            —         
expense
Net income (loss)   $  85,598     $ (496,433 )   $ 243,718     $ (778,082  )
Earnings (loss)
per common share:
Basic:
Net income (loss)   $  0.40       $ (2.32    )   $ 1.13        $ (3.63     )
Weighted average
common shares         214,788     214,164      214,786      214,154   
outstanding
Diluted:
Net income (loss)   $  0.40       $ (2.32    )   $ 1.13        $ (3.63     )
Weighted average
common shares and
common share          216,023     214,164      215,347      214,154   
equivalents
outstanding

                                                 
EXCO Resources, Inc.
Consolidated Statements of Cash Flows
(Unaudited)
                                                   
                                                   Six Months Ended June 30,
(in thousands)                                      2013        2012     
Operating Activities:
Net income (loss)                                  $ 243,718      $ (778,082 )
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depletion, depreciation and amortization             88,696         176,919
Share-based compensation expense                     6,323          5,455
Accretion of discount on asset retirement            1,246          1,911
obligations
Write-down of oil and natural gas properties         10,707         704,665
Income from equity investments                       (24,079  )     (7,127   )
Non-cash change in fair value of derivatives         5,779          73,353
Deferred income taxes                                —              —
Amortization of deferred financing costs and         6,597          6,440
discount on the 2018 Notes
Gain on divestitures                                 (186,350 )     —
Effect of changes in:
Accounts receivable                                  17,728         107,693
Other current assets                                 (1,786   )     4,997
Accounts payable and other current liabilities      2,653        (15,756  )
Net cash provided by operating activities           171,232      280,468  
Investing Activities:
Additions to oil and natural gas properties,         (132,363 )     (305,969 )
gathering systems and equipment
Property acquisitions                                (33,390  )     (2,748   )
Equity method investments                            (104     )     (10,254  )
Proceeds from disposition of property and            613,090        17,000
equipment
Restricted cash                                      27,543         95,167
Net changes in advances from Appalachia JV          8,276        5,193    
Net cash provided by (used in) investing            483,052      (201,611 )
activities
Financing Activities:
Borrowings under credit agreements                   46,757         53,000
Repayments under credit agreements                   (644,541 )     (93,000  )
Proceeds from issuance of common stock               42             297
Payment of common stock dividends                    (21,479  )     (17,132  )
Deferred financing costs and other                  (265     )    (1,623   )
Net cash used in financing activities                (619,486 )     (58,458  )
Net increase in cash                                 34,798         20,399
Cash at beginning of period                         45,644       31,997   
Cash at end of period                              $ 80,442      $ 52,396   
                                                                  
                                                                  
Supplemental Cash Flow Information:
Cash interest payments                             $ 37,059       $ 42,454
Income tax payments                                  —              —
Supplemental non-cash investing and financing
activities:
Capitalized share-based compensation               $ 3,055        $ 3,894
Capitalized interest                                 9,817          12,525
Issuance of common stock for director services       38             527
Accrued restricted stock dividends                   201            190
EXCO/HGI Partnership debt upon formation, net        58,613         —

                                                
EXCO Resources, Inc.
Consolidated EBITDA
And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data
(Unaudited)
                                                   
                     Three Months Ended June 30,   Six Months Ended June 30,
(in thousands)         2013       2012         2013        2012     
Net income (loss)    $  85,598      $ (496,433 )   $ 243,718      $ (778,082 )
Interest expense        15,105        20,369         35,297         37,133
Income tax expense      —             —              —              —
Depletion,
depreciation and       47,388      87,337       88,696       176,919  
amortization
EBITDA(1)               148,091       (388,727 )     367,711        (564,030 )
Accretion of
discount on asset       556           964            1,246          1,911
retirement
obligations
Non-cash write
down of oil and         —             428,801        10,707         704,665
natural gas
properties
(Gain) loss on
divestitures and
other                   3,041         6,673          (181,345 )     8,625
non-recurring
operating items
Equity (income)         (11,416 )     (15,033  )     (24,079  )     (7,127   )
loss
Non-cash change in
fair value of
derivative              (54,452 )     77,073         5,779          73,353
financial
instruments
Share based
compensation           4,588       2,591        6,323        5,455    
expense
Adjusted EBITDA      $  90,408      $ 112,342      $ 186,342      $ 222,852
(1)
Interest expense        (15,105 )     (20,369  )     (35,297  )     (37,133  )
Income tax expense      —             —              —              —
Amortization of
deferred financing      1,484         4,690          6,597          6,440
costs and discount
on the 2018 Notes
Non-recurring
other operating         (2,353  )     (6,673   )     (5,005   )     (8,625   )
items
Changes in working     53,585      45,355       18,595       96,934   
capital
Net cash provided
by operating         $  128,019    $ 135,345     $ 171,232     $ 280,468  
activities

                                                
                      Three Months Ended           Six Months Ended
                      June 30,                     June 30,
(in thousands)         2013       2012         2013        2012     
Statement of cash
flow data:
Cash flow provided
by (used in):
Operating             $ 128,019     $ 135,345      $ 171,232      $ 280,468
activities
Investing               (42,208 )     (33,723  )     483,052        (201,611 )
activities
Financing               (32,014 )     (79,797  )     (619,486 )     (58,458  )
activities
Other financial and
operating data:
EBITDA(1)             $ 148,091     $ (388,727 )   $ 367,711      $ (564,030 )
Adjusted EBITDA(1)      90,408        112,342        186,342        222,852
                                                                             

(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-recurring other operating items,
accretion of discount on asset retirement obligations, non-cash changes in the
fair value of derivatives, non-cash write-downs of assets, stock-based
compensation and income or losses from equity method investments. 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 agreement and the indenture governing
our 7.5% senior notes due September 15, 2018. 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.

                                                    
TGGT Holdings, LLC
EBITDA and Adjusted EBITDA Reconciliation
(Unaudited)
                                                       
                             Three Months Ended        Six Months Ended
                             June 30,                  June 30,
(in thousands)                2013      2012       2013      2012   
                                                                    
Equity income (loss)         $ 11,416     $ 15,033     $ 24,079     $ 7,127
Amortization of the
difference in the              (402   )     (402   )     (804   )     (804   )
historical basis of our
contribution to TGGT
Equity loss of other          96         1,715      287        2,594  
investments
EXCO's share of TGGT net       11,110       16,346       23,562       8,917
income (loss)
BG Group's share of TGGT      11,110     16,346     23,562     8,917  
net income (loss)
TGGT net income (loss)         22,220       32,692       47,124       17,834
Interest expense               3,083        2,683        6,423        6,557
Margin tax expense             112          30           222          268
Depreciation and              8,935      6,942      17,693     14,823 
amortization
TGGT EBITDA(1)                 34,350       42,347       71,462       39,482
Asset impairments and
non-recurring other           1,309      —          738        37,598 
operating items
TGGT Adjusted EBITDA(1)      $ 35,659    $ 42,347    $ 72,200    $ 77,080 
EXCO's share of TGGT         $ 17,830    $ 21,174    $ 36,100    $ 38,540 
Adjusted EBITDA (2)
                                                                             

(1) Earnings before interest, taxes, depreciation, depletion and amortization,
or “EBITDA” represents net income adjusted to exclude interest expense, income
taxes and depreciation and amortization. “Adjusted EBITDA” represents EBITDA
adjusted to exclude asset impairments, gains and losses on divestitures and
non-recurring other operating items. 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. 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) Represents our 50% equity share in TGGT.

                                                      
TGGT Holdings, LLC
Computation of Adjusted Net Income
(Unaudited)
                                                         
                                 Three Months Ended      Six Months Ended
                                 June 30,                June 30,
(in thousands)                    2013      2012      2013      2012
Net income (loss), GAAP          $ 22,220     $ 32,692   $ 47,124     $ 17,834
Adjustments:
(Gain) loss on asset disposal      (28    )     —          162          1,399
Asset impairment, net of           983          —          1,247        35,343
insurance recoveries
Other non-cash items              354        —         (671   )    856
Total adjustments                 1,309      —         738        37,598
Adjusted net income              $ 23,529    $ 32,692   $ 47,862    $ 55,432
                                                                      
EXCO's 50% share of TGGT's       $ 11,765    $ 16,346   $ 23,931    $ 27,716
adjusted net income (1)
                                                                        

(1) TGGT’s net income, computed in accordance with GAAP, includes certain
items not typically included by securities analysts in published estimates of
financial results. This table provides a reconciliation of GAAP net income to
a non-GAAP measure of adjusted net income.

                                                                   
EXCO Resources, Inc.
Summary of Operating Data
(Unaudited)
                                                                        
                   Three Months Ended             Six Months Ended
                   June 30,              %        June 30,              %
                   2013     2012     Change    2013     2012     Change
Production:
Oil (Mbbls)          50         182      (73 )%     152        374      (59 )%
Natural gas          43         131      (67 )%     125        253      (51 )%
liquids (Mbbls)
Natural gas          37,695     48,162   (22 )%     77,288     95,154   (19 )%
(Mmcf)
Total production     38,253     50,040   (24 )%     78,950     98,916   (20 )%
(Mmcfe) (1)
Average daily
production           420        550      (24 )%     436        543      (20 )%
(Mmcfe)
Average sales
price (before
cash settlements
of derivative
financial
instruments):
Oil (per Bbl)      $ 90.48    $ 86.38    5   %    $ 84.59    $ 91.90    (8  )%
Natural gas
liquids (per         33.98      40.15    (15 )%     36.43      46.30    (21 )%
Bbl)
Natural gas (per     3.83       2.01     91  %      3.51       2.17     62  %
Mcf)
Natural gas
equivalent (per      3.93       2.36     67  %      3.65       2.56     43  %
Mcfe)
Costs and
expenses (per
Mcfe):
Oil and natural
gas operating      $ 0.31     $ 0.38     (18 )%   $ 0.32     $ 0.42     (24 )%
costs
Production and       0.10       0.14     (29 )%     0.12       0.14     (14 )%
ad valorem taxes
Gathering and        0.61       0.52     17  %      0.61       0.53     15  %
transportation
Depletion            1.19       1.67     (29 )%     1.07       1.71     (37 )%
Depreciation and     0.05       0.08     (38 )%     0.05       0.08     (38 )%
amortization
General and          0.69       0.37     86  %      0.56       0.41     37  %
administrative

                                                     
Selected EXCO/HGI Partnership Information
(Unaudited)
                                                        
                 Three months ended June 30, 2013       Three months ended June 30, 2012
(dollars in                   Pro forma                              Pro forma     Pro
thousands,       Historical  adjustments  Pro forma   Historical  adjustments  forma
except per       EXCO         (1)           EXCO        EXCO         (1)           EXCO
unit rate)
Production:
Total
production          38,253          —         38,253       50,040      (6,361  )     43,679
(Mmcfe)
Average
production          420             —         420          550         (70     )     480
(Mmcfe/d)
Revenues:
Revenues,
excluding        $  150,332   $     —       $ 150,332   $  117,978   $ (25,156 )   $ 92,822
derivatives
Average
realized price      3.93            —         3.93         2.36        3.95          2.13
($/Mcfe)
Expenses:
Direct
operating        $  11,902    $     —       $ 11,902    $  18,863    $ (7,415  )   $ 11,448
costs
Per Mcfe            0.31            —         0.31         0.38        1.17          0.26
Production and
ad valorem          3,981           —         3,981        6,789       (3,244  )     3,545
taxes
Per Mcfe            0.10            —         0.10         0.14        0.51          0.08
Gathering and       23,408          —         23,408       25,913      (1,745  )     24,168
transportation
Per Mcfe            0.61            —         0.61         0.52        0.27          0.55
Excess of
revenues over    $  111,041   $     —       $ 111,041   $  66,413    $ (12,752 )   $ 53,661
operating
expenses
                                                                                     

                Six months ended June 30, 2013        Six months ended June 30, 2012
(dollars in                   Pro forma                              Pro forma
thousands,       Historical  adjustments  Pro forma   Historical  adjustments  Pro forma
except per       EXCO         (1)           EXCO        EXCO         (1)           EXCO
unit rate)
Production:
Total
production          78,950      (2,705  )     76,245       98,916      (12,967 )     85,949
(Mmcfe)
Average
production          436         (15     )     421          543         (71     )     472
(Mmcfe/d)
Revenues:
Revenues,
excluding        $  288,555   $ (12,657 )   $ 275,898   $  252,826   $ (55,914 )   $ 196,912
derivatives
Average
realized price      3.65        4.68          3.62         2.56        4.31          2.29
($/Mcfe)
Expenses:
Direct
operating        $  25,519    $ (3,489  )   $ 22,030    $  41,659    $ (15,835 )   $ 25,824
costs
Per Mcfe            0.32        1.29          0.29         0.42        1.22          0.30
Production and
ad valorem          9,229       (1,545  )     7,684        13,982      (6,775  )     7,207
taxes
Per Mcfe            0.12        0.57          0.10         0.14        0.52          0.08
Gathering and       47,884      (782    )     47,102       52,336      (4,247  )     48,089
transportation
Per Mcfe            0.61        0.29          0.62         0.53        0.33          0.56
Excess of
revenues over    $  205,923   $ (6,841  )   $ 199,082   $  144,849   $ (29,057 )   $ 115,792
operating
expenses

(1)The 2013 pro forma adjustments reflect the contribution of our interest in
certain properties from January 1, 2013 to February 14, 2013 and the
acquisition of certain shallow conventional assets from BG Group from January
1, 2013 to March 5, 2013. The 2012 pro forma adjustments reflect the impact of
these transactions from January 1, 2012 to June 30, 2012.

Contact:

EXCO Resources, Inc.
Chris Peracchi, 214-368-2084
Director of Finance and Investor Relations and Treasurer
www.excoresources.com