EX-99.1 2 dex991.htm PRESS RELEASE Press Release

Exhibit 99.1


LOGO    EXCO Resources, Inc.
   12377 Merit Drive, Suite 1700, LB 82, Dallas, Texas 75251
   (214) 368-2084      FAX (972) 367-3559



DALLAS, TEXAS, August 3, 2010…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced its second quarter 2010 results of operations. Highlights during the quarter include:



Net income for the second quarter 2010 was $564 million, or $2.62 per diluted share, which includes gains from divestitures. Adjusted net income, a non-GAAP measure adjusting for gains on divestitures, unrealized derivative gains and losses and other non-cash items typically not included by securities analysts in published estimates, was $0.11 per share for the second quarter 2010.



Oil and natural gas production was 26.5 Bcfe, reflecting daily production of 292 Mmcfe per day, for the second quarter 2010. Pro forma production for the second quarter 2010 was 25.5 Bcfe (280 Mmcfe per day) compared with 19.2 Bcfe (211 Mmcfe per day) pro forma second quarter 2009 production, reflecting an increase of 6.3 Bcfe, or 33%, from the prior year’s quarter which highlights the success of our Haynesville shale drilling program. Net production from our Haynesville shale operations was 11.6 Bcf (128 Mmcf per day), representing 46% of our total pro forma production during the second quarter 2010 compared with 1.9 Bcf (21 Mmcf per day), or 10% of our total production, in the pro forma second quarter 2009. Current net Haynesville volumes are in excess of 160 Mmcf per day. The following table presents the current quarter’s production and the prior year’s second quarter production on an actual and pro forma basis.


     Three months ended June 30,             
     2010    2009    Quarter to quarter change  

(in Mmcfe)

   Pro forma
adjustment (1)
    Pro forma
   Pro forma
adjustment (1)
    Pro forma
    Versus pro

Producing region:


East Texas/North Louisiana

   22,097    —        22,097    23,341    (7,973   15,368    (1,244   6,729   


   2,669    (1,085   1,584    5,025    (3,244   1,781    (2,356   (197

Permian and other

   1,781    —        1,781    2,402    (388   2,014    (621   (233


   —      —        —      5,750    (5,750   —      (5,750   —     


   26,547    (1,085   25,462    36,518    (17,355   19,163    (9,971   6,299   


(1) The pro forma adjustments reduce production volumes attributable to properties sold in 2009 and properties affected by the joint ventures with BG Group as if these sales had occurred on January 1, 2009.



Oil and natural gas revenues for the second quarter 2010 were $118 million, exclusive of the impacts of derivative financial instruments (derivatives), compared with the second quarter 2009 oil and natural gas revenues of $146 million. The lower revenues reflect the impacts from our 2009 divestitures and joint venture transactions, and were partially offset by higher realized prices for oil and natural gas, which increased by 12% from the prior year’s second quarter. When the impacts of cash settlements from our oil and natural gas derivatives are considered, the oil and natural gas revenues, as adjusted, were $165 million for the second quarter 2010 compared with $288 million for the second quarter 2009.


Adjusted EBITDA, defined as earnings before interest, taxes, depreciation, depletion and amortization and other non-cash income and expense items (a non-GAAP measure) for the second quarter 2010 was $99 million compared with $210 million in the second quarter 2009. The lower Adjusted EBITDA reflects the impacts from our 2009 divestitures and joint venture transactions, lower cash settlements from our oil and natural gas derivatives, and were partially offset by higher realized prices for oil and natural gas, which increased by 12% from the prior year’s second quarter.



On June 1, 2010, we closed our previously announced joint venture transaction with BG Group (“Appalachia JV”). Pursuant to the joint venture agreements, we sold 50% of substantially all of our Appalachian properties and undeveloped Marcellus shale acreage and received $835 million of proceeds, subject to final closing adjustments, plus a $150 million carry on future deep drilling costs. We recognized a $575 million pre-tax gain as a result of this sale. We will jointly operate the Appalachia assets with BG Group. Partnering with BG Group will allow us to accelerate our development activities in the Marcellus shale similar to what we have accomplished in the Haynesville shale.



We closed two significant acreage acquisitions during the second quarter 2010. These acquisitions, which were made jointly with BG Group, added approximately 12 Mmcf per day of existing net production as well as approximately 23,800 net acres in the Shelby Trough area of the Haynesville and Bossier shale plays in East Texas. Initial production, (or IP, the highest 24-hour average rate) rates in this area have been comparable to those being achieved by EXCO in DeSoto Parish, Louisiana. The Shelby Trough represents our second major focus area in the Haynesville and Bossier shale plays.

Douglas H. Miller, EXCO’s Chairman and CEO, commented:

“During the second quarter, we continued to accomplish our growth objectives at EXCO. We began 2010 with a pro forma production rate of 214 Mmcfe per day and exited the second quarter at over 300 Mmcfe per day. Our growth target is to average a 30% annual increase in production for the next five years with corresponding increases in reserves and cash flows. Our drilling program will be funded with internally generated cash flow as a result of our joint ventures with BG Group. Our success in the Haynesville play continues to be outstanding and we are progressing in the Marcellus. In the Haynesville, we completed two successful 80 acre spacing tests of our acreage, with one two well pad and a second pad with four wells which we simultaneously fracture stimulated. As a result of these tests, we are implementing a pad development program in DeSoto Parish on 12 units. In Appalachia, we are planning to complete three wells on a single pad in the third quarter.

“We are very pleased with our acreage and development positions in our shale plays and can accomplish our goals without any planned acquisitions, although we will continue to evaluate additional acreage purchases in the core areas of these shale plays. Additionally, as a result of current market conditions, our Board of Directors has established a stock repurchase plan that gives us the flexibility to respond to opportunities to repurchase shares as we deem appropriate.”



Net Income

Our reported net income (loss), a GAAP measure, includes certain items not typically included by securities analysts in their published estimates of financial results. Management is disclosing the non-GAAP measure of adjusted net income because it quantifies the financial impact of non-cash gains or losses resulting from derivatives, non-cash ceiling test write-downs and other items management believes affect the comparability of our results of operations which are included in the GAAP net income measure. The following table provides a reconciliation of our net income (loss) to the non-GAAP measure of adjusted net income:


     Three months ended
June 30, 2010
    Three months ended
June 30, 2009
    Six months ended
June 30, 2010
    Six months ended
June 30, 2009

(in thousands, except per share amounts)

   Amount     Per share     Amount     Per share     Amount     Per share     Amount     Per share  

Net income (loss), GAAP

   $ 564,313        $ (71,992     $ 679,881        $ (1,171,603  



Non-cash mark-to-market losses on derivative financial instruments, before taxes

     45,831          174,937          21,711          46,196     

Gain on divestitures

     (574,878       —            (574,878       —       

Non-cash write down of oil and natural gas properties

     —            —            —            1,293,579     

Income taxes on above adjustments (1)

     211,619          (69,975       221,267          (535,910  

Adjustment to deferred tax asset valuation allowance (2)

     (223,054       29,430          (269,281       469,907     

Total adjustments, net of taxes

     (540,482       134,392          (601,181       1,273,772     

Adjusted net income

   $ 23,831        $ 62,400        $ 78,700        $ 102,169     

Net income (loss), GAAP (3)

   $ 564,313      $ 2.66      $ (71,992   $ (0.34   $ 679,881      $ 3.20      $ (1,171,603   $ (5.55

Adjustments shown above (3)

     (540,482     (2.54     134,392        0.64        (601,181     (2.83     1,273,772        6.03   

Dilution attributable to stock options (4)

       (0.01       (0.01       —            —     

Adjusted net income for diluted earnings per share

   $ 23,831      $ 0.11      $ 62,400      $ 0.29      $ 78,700      $ 0.37      $ 102,169      $ 0.48   

Common stock and equivalents used for earnings per share (EPS):


Weighted average common shares outstanding

     212,497          211,089          212,293          211,042     

Dilutive stock options

     3,001          920          3,227          —       

Shares used to compute diluted EPS for adjusted net income

     215,498          212,009          215,520          211,042     


(1) The assumed income tax rate is 40% for all periods.
(2) Deferred tax valuation allowance has been adjusted to reflect impacts of adjustments.
(3) Per share amounts are based on weighted average number of common shares outstanding
(4) Represents dilution per share attributable to common stock equivalents from in-the-money stock options for periods with adjusted net income available to common shareholders.

Cash Flow

Second quarter 2010 cash flow from operations before changes in working capital and settlements of derivative financial instruments with a financing element (adjusted cash flow) was $84.1 million, a decrease from the prior year’s second quarter due primarily to lower production volumes arising from our 2009 divestitures and joint venture transactions. The following table reconciles cash flow from operations pursuant to GAAP to cash flow without working capital adjustments and derivative settlements with a financing element.


     Three months ended
June 30,
   Six months ended
June 30,

(in thousands)

   2010     2009    2010     2009

Cash flow from operations, GAAP

   $ 90,550      $ 121,607    $ 181,853      $ 226,933

Net change in working capital

     (6,443     2,179      38,946        24,365

Settlements of derivative financial instruments with a financing element

     —          52,678      (907     90,294

Cash flow from operations before changes in working capital, non-GAAP measure (1)

   $ 84,107      $ 176,464    $ 219,892      $ 341,592



(1) Cash flow from operations before working capital changes and adjustments for settlements of derivative financial instruments with a financing element is presented because management believes it is a useful financial indicator for companies in our industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company’s ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. Operating cash flow is not a measure of financial performance pursuant to GAAP and should not be used as an alternative to cash flows from operating, investing, or financing activities. We have also elected to exclude the adjustment for derivative financial instruments with a financing element as this adjustment simply reclassifies settlements from operating cash flows to financing activities. Management believes these settlements should be included in this non-GAAP measure to conform to the intended measure of our ability to generate cash to fund operations and development activities.

Operations activity and outlook

We spent $103 million on development and exploitation activities, drilling and completing 50 gross (23.8 net) wells in the second quarter 2010, compared with 42 gross (18.8 net) wells during the first quarter 2010. We had an overall drilling success rate of 98% for the second quarter 2010, as we completed 49 of the 50 wells drilled. We are successfully continuing efforts to opportunistically acquire additional leasehold in our core shale areas, where we added approximately 23,800 net acres in the Shelby Trough during the quarter. Our total capital expenditures, including leasing, net of acreage reimbursements from BG Group, midstream and corporate activities, were $135 million in the second quarter 2010. We also made equity contributions into TGGT Holdings, LLC, or TGGT, of $24 million.

In light of current natural gas prices, our recently announced acquisitions in the Shelby Trough and our Appalachia JV, we continue to monitor our capital activity and spending plans. Our activities will be focused in areas that meet our rate of return objectives or are subject to lease expirations. We have deferred drilling in the Haynesville shale in Harrison County, Texas and northern Caddo Parish, Louisiana because the IP rates and returns in these areas have been lower than in southern Caddo and DeSoto Parishes, Louisiana. Most of our acreage in these areas is held-by-production. In this environment, we will continue searching for opportunities to expand our acreage positions in the core areas of our shale plays. We currently have 28 drilling rigs operating across our portfolio, of which 20 are operated. Our projected capital spending for 2010 is presented on the following table:


(in thousands)

   July - December
2010 capital
   Total 2010
capital budget

Capital expenditures:


Development capital expenditures

   $ 64,993    $ 102,602    $ 158,950    $ 326,545

Lease purchases (1)

     8,742      12,275      41,241      62,258

Seismic (2)

     4,150      5,571      10,165      19,886

Gas gathering and water pipelines

     2,128      3,895      16,751      22,774

Corporate and other

     9,957      10,936      19,400      40,293

Capital expenditures before acquisitions

   $ 89,970    $ 135,279    $ 246,507    $ 471,756


(1) Net of acreage reimbursements from BG Group totaling $57 million.
(2) Net of seismic reimbursements from BG Group totaling $4 million.

In addition to our capital program, we have closed on $452 million of acquisitions. During 2010, we also plan to contribute up to $75 million to TGGT and expect to receive $131 million from BG Group for their participation in certain of our acquisitions.



East Texas/North Louisiana

The East Texas/North Louisiana area is comprised of the Haynesville and Bossier shale plays and the Cotton Valley sand trend, which covers portions of the East Texas Basin and the Northern Louisiana Salt Basin. This area is currently our most active development area, providing more than 80% of our total production and holding significant reserve growth potential, particularly from the shales. EXCO operates over 1,200 total wells in the area, holds interests in approximately 182,000 net acres and has a significant operations base and pipeline infrastructure.

Our development drilling focus in this region is in the Haynesville shale, where a significant portion of our acreage is located in a prolific area of the play. The Haynesville shale play is 12,000-14,000 feet deep and is being developed with horizontal wells that have 4,000 – 5,000 foot laterals resulting in 16,000 – 19,000 feet of total measured depth.

We continue to produce tight gas sand reservoirs in the Cotton Valley sand trend at depths of 6,500 to 15,000 feet. Operations in the area are generally characterized by long-life reserves and high drilling success rates. Our development programs, which are currently deferred due to the commodity price environment, have been focused on infill drilling and extension of field limits.

Haynesville shale

The Haynesville shale gas play is one of the most active natural gas plays in the United States. Our current Haynesville shale activity is located in DeSoto and Caddo Parishes in Louisiana and in Harrison, Panola, Shelby, San Augustine and Nacogdoches Counties in Texas. Our joint venture with BG Group holds interests in approximately 160,000 net acres (80,000 net to EXCO) in the Haynesville shale. Approximately half of our core area acreage is held by our existing Haynesville, Cotton Valley, Hosston and Travis Peak production. In the first half of 2010, we added approximately 26,000 net acres to our Haynesville position, including approximately 23,800 net acres in the Shelby Trough in East Texas. The Shelby Trough is a second major focus area for us outside of our core DeSoto Parish position.

Our program in the Haynesville shale play has transitioned from an appraisal and testing program in late 2008 and early 2009 to a full scale horizontal development drilling program. In early 2009, we ran three operated horizontal drilling rigs in the play, and we exited 2009 with twelve operated horizontal drilling rigs. We are currently running 18 operated horizontal drilling rigs in the play and expect to exit 2010 with 22 operated horizontal drilling rigs. We plan to drill approximately 140 operated horizontal wells in 2010. Since late 2008, we have spud over 100 operated horizontal wells and produced over 100 Bcf of gross natural gas to sales. Our average IP rate for the DeSoto area is approximately 23 Mmcf per day. Our gross operated daily gas production rate currently exceeds 500 Mmcf per day.

We continue to improve our program execution and our operational focus has yielded significant improvements in drilling and completion efficiencies. The amount of time required to drill these horizontal wells has decreased from over 70 days to approximately 40 days from spud to rig release. We are also utilizing dedicated fracture stimulation fleets resulting in greater consistency and efficiencies in our fracturing operations.



We have a strong commitment to technical evaluations to improve the understanding of our shale plays and have made appropriate investments to reduce risks. We are members of a major shale consortium, reservoir engineering consortium and several other engineering and geoscience study projects. We have acquired 2-D seismic data over a large regional area, participated in a significant 3-D seismic survey, completed installation of a broad microseismic fracture stimulation monitoring project and have additional 2-D and 3-D seismic projects in progress. In the DeSoto Parish area, we recently drilled four wells on 80-acre spacing from one drill site and then simultaneously fracture stimulated all four wells. In the same section, we drilled and equipped two vertical wells specifically for monitoring downhole microseismic activity during the fracturing operations and equipped those same two wells for long term reservoir pressure monitoring. We believe we are on the forefront among E&P companies to make these commitments for technical evaluation and long term pressure monitoring in this play.

We remain committed to reducing our impact on local water supplies and have made two major water pipeline projects a top priority. We are participating in a salt water disposal project that will gather produced saltwater across our acreage and deliver to a common point which will reduce truck traffic and dispose of produced saltwater much more efficiently and cost effectively. We are also making a significant investment in a water supply project where we will use discharge water from a local paper plant as a key water source for our fracture stimulation operations. This solution will provide relief on local water supplies, reduce truck traffic and provide an environmentally friendly option for water procurement.

Bossier shale

The Bossier shale section overlies the Haynesville shale and is as much as 1,400 feet thick. In 2009, we initiated a Bossier shale testing program with a procedure identical to one we used to evaluate the Haynesville shale. The Bossier shale is up to five times the thickness of the Haynesville shale in the DeSoto Parish area and holds significant reserve potential. We have completed two horizontal Bossier shale wells in DeSoto Parish with IP rates of 11 Mmcf per day and 13 Mmcf per day, respectively. We plan to drill and test additional Bossier horizontal test wells across our acreage in East Texas, including the Shelby Trough, and Northwest Louisiana over the next several months

Vernon/Kelleys area

The Vernon Field, located in Jackson Parish, Louisiana, accounts for approximately 28% of our current production. The field produces from the Lower Cotton Valley and Bossier Sand formations at depths ranging from 12,000 to 15,000 feet. The technical expertise obtained in the development of the Vernon Field and the exploitation of these high-pressure, high-temperature reservoirs greatly assisted in the rapid development of the Haynesville shale. While we have identified more than 100 additional well locations for infill drilling and extending the field limits, this drilling has been deferred due to the current commodity price environment. The current focus in the Vernon Field is maintaining production and minimizing our operating expense. Within the past year, we have successfully reduced our production decline rate.



East Texas/North Louisiana Cotton Valley area

Within our Cotton Valley area, we have acreage and production in Caddo and DeSoto Parishes, Louisiana and Harrison, Panola, Gregg and Rusk Counties in Texas. We are focused on producing primarily Cotton Valley sands at depths ranging from 10,400 to 11,000 feet and the Travis Peak and Hosston Sands at 7,800 to 10,000 feet. Our economic hurdles require higher product pricing to justify development drilling at this time. Our focus in 2010 is on production enhancement through recompletions and minimizing decline rates. We recompleted eight Cotton Valley wells during the first half of 2010 to add Hosston pay intervals and plan to perform up to 28 of these recompletions in the DeSoto Parish area during 2010.


The Appalachian Basin includes portions of the states of Kentucky, Ohio, Pennsylvania, Virginia, West Virginia and Tennessee and covers an area of over 185,000 square miles. The Appalachian Basin is strategically located near the high energy demand markets of the northeast United States and, as a result, the natural gas produced from the area has typically commanded a higher wellhead price relative to other North American gas areas.

Most production in the Appalachian Basin has been traditionally derived from relatively shallow, low porosity and low permeability sand and shale formations at approximate depths from 1,000 to 8,000 feet. Assets in the area are typically characterized by long reserve lives, high drilling success rates, and a large number of low productivity wells with shallow decline rates. Our operations in the area have primarily included maintaining our existing production from shallow wells and testing our Marcellus shale acreage.

The emergence of the Marcellus shale opportunity over the last several years resulted in a shift in our focus from the traditional shallow formations to the exploration and development of the Marcellus shale. We currently hold over 300,000 net acres in the Appalachian Basin, of which approximately 106,000 net acres are located in the core area of the Marcellus play. We define the core area of the Marcellus play to be geologically overpressured. We plan to concentrate our efforts in this core area, which is located in Pennsylvania and West Virginia.

Marcellus shale

The Marcellus shale play is found at approximate depths ranging from 6,000 to over 8,000 feet and typically has been exploited using horizontal drilling techniques. The Marcellus shale play extends over 400 miles in length within the Appalachian Basin. More than 70% of our Marcellus shale acreage is held-by-production, providing us with a competitive advantage since we can develop the majority of our Marcellus acreage under an optimized schedule not driven by lease term expiration.



We have a strong commitment to technical excellence, and continue to add to our technical staff. We are members of major geologic and reservoir engineering Marcellus shale consortiums, participate in several study projects, and are active in Marcellus–focused industry associations and coalitions. We have conducted 3-D seismic surveys targeting the Marcellus shale opportunity on over 53 square miles to date, with several additional 3-D surveys planned during 2010 and 2011. 2-D seismic continues to be utilized for reconnaissance. During 2009, we drilled eight gross Marcellus shale wells primarily to test and evaluate our position.

Pennsylvania area

Our Pennsylvania area encompasses 27 counties. Drilling, completion and production activities target the Marcellus shale as well as the Upper Devonian, Venanago, Bradford and Elk sandstone groups at depths from 1,800 to 8,100 feet.

During 2010, our Marcellus development program is focused in Central Pennsylvania where we have a contiguous land position within close proximity to pipeline infrastructure so we can promptly transport our production to market. We are currently running one operated horizontal drilling rig in the play. We drilled five horizontal and three vertical Marcellus wells in the first half of 2010. Our vertical well drilling is predominately for geologic and engineering data gathering and appraisal. Our most recently completed horizontal well had a 4,800 foot lateral and an IP rate of 4.0 Mmcf per day. We recently drilled three horizontal wells from a common pad, which are scheduled for completion during the third quarter of 2010. The length of these laterals are each over 5,000 feet. For the full year 2010, we plan to drill and complete 15 gross operated horizontal wells in the play and exit 2010 with three operated horizontal drilling rigs.

West Virginia area

Our West Virginia area includes 30 counties and stretches from the northern to the southern areas of the state. Drilling, completion and production activities target the Marcellus shale and multiple, laterally stratified reservoirs of the Mississippian and Devonian formations found at depths ranging from 1,500 to 8,100 feet. During 2010, we plan to drill one gross operated vertical well and participate in one gross outside operated horizontal Marcellus drill wells.


The Permian Basin, located in West Texas and the adjoining area of southeastern New Mexico, is best known as a mature oil-focused basin exploited with waterflood and other enhanced oil recovery techniques. Our activities are focused on conventional oil and natural gas properties. With the use of 3-D seismic, we are targeting prolific reservoirs with potential for multi-pay horizons. The properties are characterized by long reserve lives and low operating costs.

Sugg Ranch Field

The Sugg Ranch Field is located primarily in Irion County, Texas. We have a total working interest of 97% in the property. Production is primarily from the Canyon Sand from depths of 6,700 to 7,900 feet. We currently plan to use two operated vertical rigs to drill and complete 53 wells in 2010.




We continue to expand our midstream operations, particularly in East Texas / North Louisiana. Our 50% owned midstream subsidiary, TGGT, had revenue throughput of 1.0 Bcf per day during the second quarter 2010 and currently exceeds 1.2 Bcf per day. Our efforts in the quarter included start-up of a new treating facility in Red River Parish, Louisiana with 500 Mmcf per day of Haynesville shale production capacity. The facility became fully operational in the second quarter 2010, and we plan to have a total of approximately 1.0 Bcf per day of treating capacity by year end 2010. We continue to promptly hookup and flow our newly completed wells to sales. As we have finished the major construction phase of our header and gathering system in DeSoto Parish, we are beginning to develop a similar system in the Shelby Trough area in East Texas.

Financial Data

Our consolidated balance sheets as of June 30, 2010 and December 31, 2009, consolidated statements of operations for the three and six months ended June 30, 2010 and 2009 and consolidated statements of cash flows for the six months ended June 30, 2010 and 2009 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 4, 2010 at 8:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call (877) 312-5172 if you wish to participate and ask for the EXCO conference call ID# 86621656. The conference call will also be webcast on EXCO’s website at www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted on EXCO’s website on Tuesday, August 3, 2010, 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 18, 2010. Please call (800) 642-1687 and enter conference ID# 86621656 to hear the recording. A digital recording of the conference call will also be available on EXCO’s website.

Additional information about EXCO Resources, Inc. may be obtained by contacting EXCO’s Chairman, Douglas H. Miller, or its President, Stephen F. Smith, at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting EXCO’s website at www.excoresources.com. EXCO’s SEC filings and press releases can be found under the Investor Relations tab.


We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this presentation, and the risk factors included in the Annual Report on Form 10-K for the year ended December 31, 2009 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 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. Beginning with reserves reported for the year ended December 31, 2009, the SEC permits optional disclosure of “probable” and “possible” reserves in its filings with the SEC. 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 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, 2009, which is available on our website at www.excoresources.com under the Investor Relations tab.



EXCO Resources, Inc.

Consolidated balance sheet


(in thousands)

   June 30,
    December 31,



Current assets:


Cash and cash equivalents

   $ 98,027      $ 68,407   

Restricted cash

     75,246        58,909   

Accounts receivable, net:


Oil and natural gas

     63,362        56,485   

Joint interest

     88,944        47,104   

Interest and other

     17,651        10,832   


     12,600        15,830   

Derivative financial instruments

     102,507        138,120   


     40,471        6,401   

Total current assets

     498,808        402,088   

Equity investments

     288,143        216,987   

Oil and natural gas properties (full cost accounting method):


Unproved oil and natural gas properties

     622,294        492,882   

Proved developed and undeveloped oil and natural gas properties

     2,114,990        1,875,749   

Accumulated depletion

     (1,207,745     (1,132,604

Oil and natural gas properties, net

     1,529,539        1,236,027   

Gas gathering assets

     145,954        180,506   

Accumulated depreciation and amortization

     (20,939     (22,841

Gas gathering assets, net

     125,015        157,665   

Office and field equipment, net

     24,238        31,771   

Deferred financing costs, net

     18,756        7,602   

Derivative financial instruments

     39,912        34,677   


     218,256        269,656   

Other assets

     11,234        2,421   

Total assets

   $ 2,753,901      $ 2,358,894   



EXCO Resources, Inc.

Consolidated balance sheet


(in thousands, except per share and share data)

   June 30,
    December 31,

Liabilities and shareholders’ equity


Current liabilities:


Accounts payable and accrued liabilities

   $ 87,368      $ 112,991   

Revenues and royalties payable

     106,693        79,356   

Accrued interest payable

     16,302        16,193   

Current portion of asset retirement obligations

     900        900   

Income taxes payable

     5,210        210   

Derivative financial instruments

     639        3,264   

Current maturities of long-term debt

     446,831        —     

Total current liabilities

     663,943        212,914   

Long-term debt, net of current maturities

     477,500        1,196,277   

Deferred income taxes

     —          —     

Derivative financial instruments

     5,648        11,688   

Asset retirement obligations and other long-term liabilities

     60,327        78,427   

Commitments and contingencies

     —          —     

Shareholders’ equity:


Preferred stock, $0.001 par value; authorized shares - 10,000,000; issued and outstanding shares - 200,000 presented above none issued and outstanding

     —          —     

Common stock, $0.001 par value; authorized shares - 350,000,000; issued and outstanding shares - 212,648,328 at June 30, 2010 and 211,905,509 at December 31, 2009

     213        212   

Additional paid-in capital

     3,124,991        3,105,238   

Accumulated deficit

     (1,578,721     (2,245,862

Total shareholders’ equity

     1,546,483        859,588   

Total liabilities and shareholders’ equity

   $ 2,753,901      $ 2,358,894   



EXCO Resources, Inc.

Consolidated statement of operations



     Three months ended
June 30,
    Six months ended
June 30,

(in thousands, except per share data)

   2010     2009     2010     2009  



Oil and natural gas

   $ 118,344      $ 146,252      $ 249,338      $ 318,460   


     —          12,942        —          29,955   

Total revenues

     118,344        159,194        249,338        348,415   

Costs and expenses:


Oil and natural gas production

     31,024        48,394        58,082        101,512   

Midstream operating

     —          11,719        —          30,169   

Gathering and transportation

     12,873        4,055        23,986        7,952   

Depreciation, depletion and amortization

     45,339        55,180        84,157        136,974   

Write-down of oil and natural gas properties

     —          —          —          1,293,579   

Accretion of discount on asset retirement obligations

     1,001        2,018        2,090        4,089   

General and administrative

     25,866        22,488        52,285        43,035   

Gain on divestures and other operating items

     (574,946     8,382        (575,353     7,977   

Total costs and expenses

     (458,843     152,236        (354,753     1,625,287   

Operating income (loss)

     577,187        6,958        604,091        (1,276,872

Other income (expense):


Interest expense

     (14,476     (46,891     (25,110     (83,023

Gain (loss) on derivative financial instruments

     707        (31,017     99,856        190,367   

Other income

     57        13        117        35   

Equity income

     5,290        —          5,379        —     

Total other income (expense)

     (8,422     (77,895     80,242        107,379   

Income (loss) before income taxes

     568,765        (70,937     684,333        (1,169,493

Income tax expense

     4,452        1,055        4,452        2,110   

Net income (loss)

   $ 564,313      $ (71,992   $ 679,881      $ (1,171,603

Earnings (loss) per common share:




Net income (loss)

   $ 2.66      $ (0.34   $ 3.20      $ (5.55

Weighted average common shares outstanding

     212,497        211,089        212,293        211,042   



Net income (loss)

   $ 2.62      $ (0.34   $ 3.15      $ (5.55

Weighted average common and common equivalent shares outstanding

     215,498        211,089        215,520        211,042   



EXCO Resources, Inc.

Consolidated statement of cash flows



     Six months ended June 30,  

(in thousands)

   2010     2009  

Operating Activities:


Net income (loss)

   $ 679,881      $ (1,171,603

Adjustments to reconcile net income (loss) to net cash provided by operating activities:


Depreciation, depletion and amortization

     84,157        136,974   

Stock option compensation expense

     8,463        6,480   

Accretion of discount on asset retirement obligations

     2,090        4,089   

Write-down of oil and natural gas properties

     —          1,293,579   

Gain on divestitures


Income from equity investments

     (5,379     —     

Non-cash change in fair value of derivatives

     21,711        46,196   

Cash settlements of assumed derivatives

     907        (90,294

Deferred income taxes

     —          2,110   

Amortization of deferred financing costs and premium on 7 1/4% senior notes due 2011

     3,847        23,767   

Effect of changes in:


Accounts receivable

     (65,218     27,300   

Other current assets

     (4,081     (3,497

Accounts payable and other current liabilities

     30,353        (48,168

Net cash provided by operating activities

     181,853        226,933   

Investing Activities:


Additions to oil and natural gas properties, gathering systems and equipment

     (263,361     (267,405

Property acquisitions

     (438,382     (62,963

Restricted cash

     (16,337     (37,500

Deposit on pending divestitures

     —          57,688   

Investment in equity investments

     (68,500     —     

Proceeds from disposition of property and equipment

     956,296        55,783   

Advances to Appalachia JV

     (30,448     —     

Net cash provided by (used in) investing activities

     139,268        (254,397

Financing Activities:


Borrowings under credit agreements

     1,352,399        52,949   

Repayments under credit agreements

     (1,622,463     (22,740

Proceeds from issuance of common stock

     9,091        1,648   

Payment of common stock dividends

     (12,740     —     

Settlements of derivative financial instruments with a financing element

     (907     90,294   

Deferred financing costs and other

     (16,881     (20,468

Net cash provided by (used in) financing activities

     (291,501     101,683   

Net increase in cash

     29,620        74,219   

Cash at beginning of period

     68,407        57,139   

Cash at end of period

   $ 98,027      $ 131,358   

Supplemental Cash Flow Information:


Cash interest payments

   $ 25,520      $ 72,718   

Supplemental non-cash investing and financing activities:


Capitalized stock option compensation

   $ 2,175      $ 1,180   

Capitalized interest

   $ 6,114      $ 2,797   

Issuance of common stock for director services

   $ 25      $ 35   



EXCO Resources, Inc.

Consolidated EBITDA

And adjusted EBITDA reconciliations and statement of cash flow data



     Three months ended
June 30,
    Six months ended
June 30,

(in thousands)

   2010     2009     2010     2009  

Net income (loss)

   $ 564,313      $ (71,992   $ 679,881      $ (1,171,603

Interest expense

     14,476        46,891        25,110        83,023   

Income tax expense

     4,452        1,055        4,452        2,110   

Depreciation, depletion and amortization

     45,339        55,180        84,157        136,974   


     628,580        31,134        793,600        (949,496

Accretion of discount on asset retirement obligations

     1,001        2,018        2,090        4,089   

Non-cash write-down of oil and natural gas properties

     —          —          —          1,293,579   

Gain on divestitures

     (574,878     —          (574,878     —     

Equity method income

     (5,290     —          (5,379     —     

Non-cash change in fair value of derivative financial instruments

     45,831        173,156        23,729        50,201   

Stock based compensation expense

     3,854        3,257        8,463        6,480   

Adjusted EBITDA (1)

   $ 99,098      $ 209,565      $ 247,625      $ 404,853   

Interest expense (2)

     (14,476     (45,110     (27,128     (87,028

Income tax expense

     (4,452     (1,055     (4,452     (2,110

Amortization of deferred financing costs, premium on 7 1/4% senior notes due 2011 and discount on long-term debt

     3,937        12,009        3,847        23,767   

Deferred income taxes

     —          1,055        —          2,110   

Changes in operating assets and liabilities

     6,443        (2,179     (38,946     (24,365

Settlements of derivative financial instruments with a financing element

     —          (52,678     907        (90,294

Net cash provided by operating activities

   $ 90,550      $ 121,607      $ 181,853      $ 226,933   


     Three months ended
June 30,
    Six months ended
June 30,

(in thousands)

   2010     2009     2010     2009  

Statement of cash flow data (unaudited):


Cash flow provided by (used in):


Operating activities

   $ 90,550      $ 121,607      $ 181,853      $ 226,933   

Investing activities

     263,088        (69,882     139,268        (254,397

Financing activities

     (303,415     34,125        (291,501     101,683   

Other financial and operating data:



     628,580        31,134        793,600        (949,496

Adjusted EBITDA(1)

     99,098        209,565        247,625        404,853   



Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude non-cash write-downs of oil and natural gas properties, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, stock-based compensation and equity method income in TGGT and other equity 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 1/4% senior notes. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to us. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures.



(2) Excludes non-cash changes in fair value of $0 and $1.8 million for the three months ended June 30, 2010 and 2009, respectively, and $2.0 million and $4.0 million for the six months ended June 30, 2010 and 2009, respectively, for interest rate swaps included in GAAP interest expense.



EXCO Resources, Inc.

Summary of operating data


     Three months ended
June 30,
   %     Six months ended
June 30,
     2010    2009    Change     2010    2009    Change  



Oil (Mbbls)

     168      485    -65     327      1,012    -68

Gas (Mmcf)

     25,539      33,608    -24     48,376      66,792    -28

Oil and natural gas (Mmcfe)

     26,547      36,518    -27     50,338      72,864    -31

Average sales prices (before derivative financial instrument activities):


Oil (per Bbl)

   $ 74.44    $ 56.08    33   $ 74.83    $ 46.34    61

Gas (per Mcf)

     4.14      3.54    17     4.65      4.07    14

Total production (per Mcfe)

     4.46      4.00    12     4.95      4.37    13

Average costs (per Mcfe):


Oil and natural gas operating costs

   $ 0.85    $ 1.07    -21   $ 0.83    $ 1.09    -24

Production and ad valorem taxes

     0.32      0.26    23     0.33      0.30    10

Gathering and transportation costs

     0.48      0.11    336     0.48      0.11    336


     1.55      1.32    17     1.49      1.69    -12

Depreciation and amortization

     0.16      0.19    -16     0.18      0.19    -5

General and administrative

     0.97      0.62    56     1.04      0.59    76