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Press release from Business Wire

EXCO Resources, Inc. Reports Fourth Quarter and Full Year 2011 Results

Thursday, February 23, 2012

EXCO Resources, Inc. Reports Fourth Quarter and Full Year 2011 Results16:50 EST Thursday, February 23, 2012 DALLAS (Business Wire) -- EXCO Resources, Inc. (NYSE: XCO) today announced fourth quarter and full year operating and financial results for 2011. Adjusted net earnings, a non-GAAP measure, were $0.09 per diluted share for the fourth quarter and $0.56 per diluted share for the full year, as adjusted for non-cash derivative gains and losses, a fourth quarter 2011 non-cash ceiling test write-down of oil and natural gas properties, gains on divestitures, costs incurred in connection with a buyout proposal received from our Chairman and Chief Executive Officer and other items typically not included by securities analysts in published estimates. Our GAAP results were a net loss of $0.78 per diluted share for the fourth quarter and net income of $0.10 per diluted share for the full year. The fourth quarter GAAP loss reflects a pre-tax non-cash ceiling test write-down of $233 million. Oil and natural gas revenues for the fourth quarter were $179 million, exclusive of derivative financial instrument activities (derivatives), and $231 million inclusive of cash settlements of derivatives. Oil and natural gas revenues for the full year were $754 million, exclusive of derivatives, and $890 million inclusive of cash settlements from derivatives. Oil and natural gas production was 51 Bcfe for the fourth quarter 2011, or 552 Mmcfe per day, which represents a 58% increase from fourth quarter 2010 production of 32 Bcfe, or 350 Mmcfe per day. During the fourth quarter 2011, our production continued to be negatively impacted by shut-in volumes resulting from the May 2011 incident at a treating facility operated by our jointly-owned midstream entity with BG Group in East Texas and North Louisiana, TGGT Holdings, LLC (TGGT), shutting-in of volumes for an accelerated tubing program, an increased emphasis on choke management and the deferral of certain well completions. We expect the TGGT treating facility to begin treating volumes late in the first quarter of 2012. The increased production highlights the success of our Haynesville shale drilling program where we produced 37 Bcf of natural gas (407 Mmcf per day), representing 73% of our total production during the fourth quarter 2011 compared with 19 Bcf (206 Mmcf per day), or 59% of our total production, in the fourth quarter 2010. For the full year 2011, our Haynesville shale production was 71% of our total production compared with 49% for the full year 2010. We currently estimate our total company net production to average approximately 500 Mmcfe per day for the full year 2012. Our direct operating costs were $0.47 per Mcfe for the fourth quarter 2011 and $0.46 per Mcfe for the full year 2011. This represents a 25% decrease from fourth quarter 2010 and a 39% decrease from full year 2010 reflecting the low cost operations of our Haynesville shale which averaged $0.08 per Mcfe during 2011. Adjusted earnings before interest, taxes, depreciation, depletion and amortization and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the fourth quarter was $151 million, which represents a 32% increase from fourth quarter 2010 adjusted EBITDA of $114 million. Our full year 2011 adjusted EBITDA was $605 million, which represents a 38% increase from full year 2010 adjusted EBITDA of $440 million. Our year end 2011 estimated proved reserves were 1.3 Tcfe. We replaced 110% of our production resulting in a three year finding and development cost of $1.35 per Mcfe through the drill bit and an “all-in” finding and development cost of $1.56 per Mcfe. TGGT had average throughput in excess of 1.5 Bcf per day during the fourth quarter 2011, a 50% increase from fourth quarter 2010 throughput of 1.0 Bcf per day. Our investment in TGGT is accounted for as an equity investment. We reported $33 million of equity income for the full year 2011 which is a 94% increase from $17 million for the full year 2010. In addition, our 50% interest in TGGT's adjusted EBITDA was $56.0 million for the full year 2011, which is not reflected in our adjusted EBITDA. Douglas H. Miller, EXCO's Chief Executive Officer, commented, “2011 was a solid year of operational and financial achievement for EXCO as we set production records and grew our cash flow and EBITDA. Our production increased by 63% to an average rate of 501 Mmcfe per day for the year, and we exited the year at 545 Mmcfe per day. We increased our proved developed reserves by 22% to 983 Bcfe and ended the year with 74% of our proved reserves in the proved developed category. We continued to exploit our shale properties in the Haynesville, Bossier and Marcellus shales with excellent results. Despite a 10% reduction in realized prices, we grew our EBITDA by 38% as a result of our strong production growth coupled with a 29% decrease in our total cash costs on an Mcfe basis. "In response to very weak natural gas prices, we plan to significantly reduce our drilling activities during 2012. We plan to operate an average of nine rigs in the Haynesville shale and three in the Marcellus shale during 2012 compared to 22 rigs in the Haynesville shale and four in the Marcellus shale during 2011. We will continue to manage our balance sheet, cash flows and debt levels to ensure that we have an appropriate level of liquidity. "We have historically emphasized acquisitions of producing properties with upside potential as an important part of our strategy. We plan to actively seek conventional and shale producing properties for acquisition during 2012, including properties with natural gas, natural gas liquids and oil production. We also plan to continue to exploit our oil and natural gas liquids upside on our Permian Basin holdings. "With our strategic planning, financial position and focused personnel, we're confident we will successfully meet our 2012 targets. "In spite of the current negative bias toward natural gas, we have significant reserves, acreage and infrastructure assets in the two most prolific and low cost natural gas plays in the country, and we will continue to prudently develop our assets.” Net income Our reported net income 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 to non-GAAP measures of adjusted net income:   Three months ended   Twelve months endedDecember 31, 2011   December 31, 2010December 31, 2011   December 31, 2010(in thousands, except per share amounts)Amount   Per shareAmount   Per shareAmount   Per shareAmount   Per share Net income (loss), GAAP $ (166,652 ) $ (72,851 ) $ 22,596 $ 671,926 Adjustments: Non-cash mark-to-market losses on derivative financial instruments, before taxes (36,425 ) 60,344 (84,313 ) 68,921 Non-cash write down of oil and natural gas properties 233,239 - 233,239 - One time deferred financing cost write-off 1,689 - 1,689 - Gains from early termination of derivative financial instruments - - - (37,936 ) (Gain) loss on divestitures and non-recurring other operating items (1) 118 54,912 27,660 (513,524 ) Income taxes on above adjustments (2) (79,448 ) (46,103 ) (71,310 ) 193,016 Adjustment to deferred tax asset valuation allowance (3)   66,661     27,977     (9,036 )   (267,806 ) Total adjustments, net of taxes   185,834     97,130     97,929     (557,329 ) Adjusted net income $ 19,182   $ 24,279   $ 120,525   $ 114,597     Net income (loss), GAAP (4) (166,652 ) $ (0.78 ) (72,851 ) $ (0.34 ) 22,596 $ 0.11 671,926 $ 3.16 Adjustments shown above (4)   185,834   0.87   97,130   0.46   97,929   0.46   (557,329 ) (2.62 ) Adjusted net income 19,182 24,279 120,525 114,597 Dilution attributable to stock options (5)   -   -     -     (0.01 )   -     (0.01 )   -     (0.01 ) Adjusted net income for diluted earnings per share $ 19,182   $ 0.09   $ 24,279   $ 0.11   $ 120,525   $ 0.56   $ 114,597   $ 0.53     Common stock and equivalents used for earnings per share (EPS): Weighted average common shares outstanding 214,137 212,791 213,908 212,465 Dilutive stock options   1,479     3,334     2,797     3,270   Shares used to compute diluted EPS for adjusted net income (loss)   215,616     216,125     216,705     215,735   (1) The twelve months ended December 31, 2011 reflect costs associated with litigation reserves, our special committee's review of strategic alternatives and certain non-cash asset impairments. The three months ended December 31, 2010, included approximately $50 million of adjustments to a gain recognized from the formation of our Appalachia joint venture and special committee costs. The twelve months ended December 31, 2010 included an adjusted gain of $529 million from the Appalachia joint venture and additional costs incurred by our special committee in connection with the buyout proposal received from our Chairman and Chief Executive Officer.(2) The assumed income tax rate is 40% for all periods.(3) Deferred tax valuation allowance has been adjusted to reflect impacts of adjustments.(4) Per share amounts are based on weighted average number of common shares outstanding.(5) Represents dilution per share attributable to common stock equivalents from in-the-money stock options. Cash flow and current liquidity Our cash flow from operations before working capital changes was $137 million for the fourth quarter and $554 million for the full year. During 2011, we used cash flow and our credit agreement to fund our drilling and development programs.   Three months ended     Twelve months ended   December 31,%December 31,%(in thousands)2011   2010change2011   2010   change Cash flow from operations, GAAP $ 73,209 $ 63,925 $ 428,543 $ 339,921 Net change in working capital 64,551 33,329 103,973 79,499 Non-recurring other operating items (474 ) 9,050 21,339 15,364 Gains from early termination of derivative financial instruments - - - (37,936 ) Settlements of derivative financial instruments with a financing element - - - (907 ) Cash flow from operations before changes in working capital, non-GAAP measure (1) $ 137,286   $ 106,304 29 % $ 553,855 $ 395,941   40 % (1) Cash flow from operations before working capital changes, non-recurring other operating items, early termination of derivatives and adjustments for settlements of derivative financial instruments with a financing element 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. 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. Non-recurring other operating items have been excluded as they do not reflect our on-going operating activities. As of February 17, 2012, $1.1 billion was drawn under our credit agreement and we had $150 million of cash, including restricted cash used to pre-fund our drilling program in East Texas/North Louisiana. Our available borrowing under our credit agreement as of February 17, 2012, including cash and restricted cash was $594 million. Currently, our credit agreement's borrowing base is $1.6 billion. Our next borrowing base redetermination is scheduled in April 2012. Operations Activity and Outlook We spent $168 million on development and exploitation activities, drilling and completing 65 gross (23.2 net) wells in the fourth quarter 2011, compared with 79 gross (41.2 net) wells during the third quarter 2011. We spent $820 million of net capital on full year 2011 development and exploration activities as we drilled and completed 335 gross (143.8 net) wells during 2011. Our 2011 net capital expenditures reflect the benefit of the BG carry in East Texas/North Louisiana of $30 million and $72 million in Appalachia. As of December 31, 2011, the remaining balance of the carry in Appalachia was approximately $55 million. We had an overall drilling success rate of 97% for the fourth quarter 2011, while our full year 2011 drilling success rate was 99%. We now have 8,404 gross (4,090.7 net) wells in our portfolio of which 94% are operated. Our total capital expenditures, including leasing, net of acreage reimbursements from BG Group, were $200 million in the fourth quarter 2011. Our adjusted 2012 capital budget, as approved by our Board of Directors, totals $470 million, and will fund the drilling and completion of 176 gross (77.2 net) wells, among other activities. Our capital spending for the fourth quarter and full year 2011 and expected 2012 capital expenditures are presented in the following table:   2011 Actual Spending   (in thousands)Fourth Quarter   Full Year2012 Budget Development and exploration $ 168.1 $ 820.3 $ 359.0 Field operations   15.5   35.2   33.0 Water pipelines/gathering 0.5 6.5 13.0 Lease purchases (1) (1.6 ) 31.5 13.0 Seismic 2.2 10.1 2.0 Corporate and other 8.3 35.6 25.0 Capitalized interest   6.9     30.1   25.0 Total capital expenditures $ 199.9   $ 969.3 $ 470.0   (1) Net of acreage reimbursements from BG Group totaling $9.1 million and $31.9 million for the fourth quarter and full year periods, respectively. We also closed $396 million of acquisitions, net of $359 million of reimbursements received from BG Group, during 2011, all of which were in our Haynesville and Marcellus operating areas. Pursuant to our joint development agreements, BG Group has the right to participate for 50% of our leasing and acquisitions we close within our areas of mutual interest (AMI) in East Texas/North Louisiana and Appalachia. East Texas/North Louisiana Our East Texas/North Louisiana assets include our 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. East Texas/North Louisiana is our largest division in terms of production and reserves, and our primary targets across this region include the Haynesville and Bossier shales. We hold approximately 64,500 net acres in these shale plays, which is down 11,500 acres from December 31, 2010 as we released acreage that we deemed to be non-prospective. We also have production from the Cotton Valley, Travis Peak, Pettet and Hosston formations in this region. Currently, our emphasis is primarily upon exploitation of our acreage in the Haynesville shale play, while arresting declines in our Cotton Valley, Travis Peak, Pettet and Hosston formations. We continue to seek additional acreage that is complementary to our existing acreage, operations and pipeline infrastructure. Haynesville Shale The Haynesville shale play is one of the most prolific natural gas plays in the United States. Our Haynesville shale acreage is primarily located in DeSoto and Caddo Parishes in Louisiana and in Harrison, Panola, Shelby, San Augustine and Nacogdoches counties in East Texas. The majority of our acreage is held by our existing Haynesville, Cotton Valley, Hosston and Travis Peak production. We completed our first Haynesville shale horizontal well in late 2008. Our drilling program in the Haynesville shale play is concentrated in our two core areas - DeSoto Parish, Louisiana and the Shelby Area, which includes Shelby, San Augustine and Nacogdoches Counties, in East Texas. Through December 31, 2011, we had spud 333 operated horizontal wells and produced more than 583.4 Bcf of gross natural gas to sales. Throughout most of 2011, we operated 22 horizontal drilling rigs in the play, but we ended 2011 with 18 operated horizontal drilling rigs in the Haynesville shale. We drilled and completed 170 gross operated Haynesville shale wells (67.6 net) during 2011 in the region and realized a 100% success rate of which 31 gross (10.9 net) were drilled and completed in the fourth quarter and deferred the completion of 4 gross (0.6 net) wells. As of December 31, 2011, we averaged a gross operated daily shale gas production rate of approximately 1.2 Bcf per day with approximately 296 gross per day curtailed. Including non-operated volumes, we exited 2011 with net Haynesville production of 406 Mmcf per day. Our operational focus has resulted in significant improvements in drilling and completion efficiencies. In DeSoto Parish, we continue to achieve improved drilling time performance. We have set several drilling records in the play including single bit runs from surface to intermediate hole depth and multiple single bit runs from intermediate to production hole total depth, typically 16,500 feet. In addition to our success in reducing well costs with drilling time improvements and efficiencies, we are also focused on optimizing completions. Almost 50% of our well cost is incurred during the completion phase. We plan to implement cost effective and efficient design changes as part of our manufacturing program. We are utilizing two dedicated fracture stimulation fleets and continue to see greater consistency and efficiencies in our fracturing operations. Recently, we re-bid our fracture stimulation services, which resulted in a reduction of fracture stimulation costs of approximately 25-30% per frac stage. Our efforts and agreements have provided consistent availability of completion equipment and personnel, and we have maintained a proper alignment with our drilling pace to keep a low inventory of wells waiting on completion. We target a minimum working inventory of completions and design our program to flow gas directly to the sales line once the well is completed. We have no wells currently waiting on pipeline, primarily as a result of close coordination with TGGT, which installs gathering lines in concert with our drilling operations in most of our development areas. In response to current natural gas prices, we plan to further reduce our operated rig count. We expect to operate an average of approximately nine drilling rigs to spud approximately 70 operated wells in the play during 2012. We also plan to slow the pace of completions to a total of 81 wells in the Haynesville/Bossier shale in 2012, including 52 carried-in wells from 2011, and end 2012 with 41 wells to be carried into 2013 for completion. DeSoto Parish Our DeSoto Parish position includes what we believe to be the most prolific area of the Haynesville shale play. We are developing DeSoto Parish primarily on 80-acre spacing in a manufacturing mode utilizing multi-well pad development. Our manufacturing process typically involves four drilling rigs per 640-acre unit to simultaneously drill all wells in the unit, followed by two fracture stimulation fleets to simultaneously complete all wells in the unit. We believe this approach to development maximizes value and recovery of reserves. The multi-well pad design minimizes surface impact and provides for a more capital efficient gathering and production system layout than can be achieved with single well locations. By the end of 2011, we had developed 25 units on 80-acre spacing. At December 31, 2011 we had 12 drilling rigs running in DeSoto Parish and had a total of 223 horizontal wells flowing to sales with a total gross production rate of approximately 955 Mmcf per day (300.6 Mmcf per day net). We plan to drill an additional eight units during 2012. Shelby Area In 2010, we acquired a significant acreage position in the Shelby Area of East Texas, our second core area of the Haynesville shale play. Since this area had few producing wells at the time of acquisition, our efforts focused on establishing and holding acreage, delineating productivity, testing different completion designs and evaluating different flowback methodologies. In late 2011 we began a significant spacing test to fully develop the Haynesville and Bossier shales in two units. Our 16 well, two zone testing and evaluation program is the next phase required to properly evaluate the Haynesville/Bossier shale well spacing to assess the proper development strategy. Our plans are to evaluate the performance of this spacing pilot before proceeding with additional unit development. We expect to complete the wells by late in the first quarter of 2012 and flow them back immediately thereafter. As part of our efforts to evaluate the performance of the various spacing patterns, we drilled a 14,500 foot depth vertical monitor well solely for microseismic and pressure monitoring purposes. We will monitor multiple fracture stimulation stages with downhole microseismic survey tools followed by installation of permanent downhole gauges to measure and monitor the reservoir pressure in the Haynesville shale as the unit produces. By enhancing our understanding of reservoir performance, we believe we will be able to maximize the estimated ultimate recovery (EUR) from our drilling and completion program. We used a monitor well with the same design early in our DeSoto Parish development, and it provided valuable reservoir information. This original monitor well is still in use today. At December 31, 2011 we had six drilling rigs running in the Shelby Area. We presently plan to defer drilling in this area while we evaluate our testing program results. We currently have a total of 55 horizontal wells flowing to sales in the Shelby Area with a total gross production rate of approximately 225 Mmcf per day (76.2 Mmcf per day net). Haynesville/Bossier shale budget Our budgeted capital expenditures in the Haynesville/Bossier shale in 2012 total $296 million, of which $272 million will fund the drilling of approximately 70 operated gross (19.9 net) and completion of 81 operated gross (26.3 net) horizontal shale wells. We are planning to run an average of nine operated rigs in this area throughout the year. Cotton Valley, Hosston, Travis Peak, Pettet Our Vernon Field in Jackson Parish, Louisiana is our most significant producing field in this group of assets as it produces approximately 55 Mmcf per day of net natural gas volumes 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 and Bossier shale. With current low commodity prices, the primary focus in the Vernon Field is to minimize our operating expense while maintaining production. We have reduced our production decline rate in the field over the last two years. We have additional acreage and production in Caddo and DeSoto Parishes, Louisiana, primarily in four fields—Holly, Kingston, Caspiana and Longwood. We also have acreage and production in Harrison, Panola, and Gregg Counties in Texas, primarily across three fields—Carthage, Waskom, and Danville. We are focused on producing primarily from 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. Due to low commodity prices, we are not actively drilling in these formations. We maintain a strong emphasis on base production performance and focus on operating expense reductions. We typically run multiple service rigs replacing tubing, changing pumps, cleaning out fill and implementing general repairs to maintain optimum production levels. We currently have a total of 1,064 wells flowing to sales from our Cotton Valley, Hosston, Travis Peak and Pettet assets with a total gross operated production rate of approximately 153 Mmcfe per day (81.8 Mmcfe per day net). Appalachia The Appalachian Basin includes portions of the states of Kentucky, New York, 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. Most production in the Appalachian Basin has been traditionally derived from relatively shallow, low porosity and low permeability sand and shale formations at depths from approximately 1,000 to over 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. We currently operate a total of 6,041 vertical shallow wells flowing to sales with a total gross production rate of approximately 55 Mmcf per day (16.5 Mmcf per day net). Our Pennsylvania area encompasses 22 counties. Drilling, completion and production activities primarily target the Marcellus shale. We plan to drill 49 gross operated (13.4 net) Marcellus shale wells in Pennsylvania during 2012. Our West Virginia area includes 17 counties and stretches from the northern to the southern areas of the state. Drilling, completion and production activities primarily target the Marcellus shale. We have no plans to drill in West Virginia during 2012 noting that the majority of our prospective Marcellus shale acreage in West Virginia is held-by-production. Over the last several years, we have shifted our focus from the traditional shallow development to exploration and development of the Marcellus shale. We currently hold approximately 326,000 net acres in the Appalachian Basin with approximately 140,200 net acres prospective for the Marcellus shale. Marcellus shale The 2011 program was a combination of appraisal and development wells in Northeast Pennsylvania, which includes Sullivan and Lycoming Counties and our Central Area which includes mainly Armstrong, Jefferson and Westmoreland counties. In Pennsylvania, we operate 56 gross wells (19.4 net) which currently produce 91 Mmcf per day (23.6 Mmcf per day net). The Northeast Pennsylvania area was acquired from Chief Oil and Gas LLC in early 2011. Our position, which totals approximately 28,000 net acres, established a core area where we quickly moved into manufacturing mode by drilling, then completing multi wells on a pad. The development wells in Northeast Pennsylvania had average initial production rates of approximately 5.2 Mmcf per day from an average lateral length of 3,600 feet. We currently have a total of 34 horizontal wells flowing to sales with a total gross production rate of approximately 65 Mmcf per day (12.9 Mmcf per day net). During 2011, we drilled and completed 13 gross (3.3 net) wells. In our Central Pennsylvania area, we have drilled mainly appraisal and spacing tests. During 2011, we added to our position by acquiring approximately 15,000 net acres. A significant amount of data has been collected and is being used to formulate a development plan based on the preliminary performance results in each area. During 2011, we drilled and completed 16 gross (8.0 net) wells. The wells in Central Pennsylvania had average initial production rates averaging 3.7 Mmcf per day from an average lateral length of 3,700 feet. We currently have a total of 22 horizontal wells flowing to sales with a total gross production rate of approximately 26 Mmcf per day (10.7 Mmcf per day net). We continue to build our core positions in Central and Northeast Pennsylvania. During 2012, our development capital will be primarily focused in Northeast Pennsylvania, particularly where we have realized strong results, have significant acreage, and have market access that is either existing or currently under construction. We have a significant amount of held-by-production acreage. Of the acreage that is not held-by-production, only 1,499 net acres are scheduled to expire this year. We continue to see improvement in cost performance metrics. Total well costs were down approximately 13% for 2011 as compared to 2010, with meaningful reductions in both drilling and completion costs. Improvements in drilling times, water management infrastructure, efficiencies due to multi-well pad drilling and single sourcing of services were among the key drivers to our cost reductions in 2011. These metrics will continue to improve as infrastructure is added, and key findings from our 2011 program are implemented. We currently have four horizontal drilling rigs operating in the basin with plans to exit 2012 with three operated rigs. The 2012 drilling plan primarily entails development in the Northeast Pennsylvania area. We plan to drill 47 gross (12.9 net) operated development wells and 2 gross (0.5 net) operated appraisal wells while spending net drilling and completion capital totaling approximately $55 million, after reduction for $55 million of BG carry. All of our planned 2012 drilling activity is located in areas that either have sufficient natural gas markets and immediate take away capacity or a defined strategy to be sales ready by year end 2012. Permian 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. We are evaluating acquisition opportunities in this region. Sugg Ranch Field The Sugg Ranch Field is located primarily in Irion County, Texas. We own a 97% interest in the property, and we operate 388 gross producing wells in this field. Production is primarily from the Canyon Sand from depths of 6,700 to 7,900 feet. We currently plan to use one operated drilling rig to drill 37 gross (35.9 net) wells in 2012. We are currently evaluating our acreage for additional conventional and shale potential. Our Sugg Ranch properties contain significant amounts of oil and natural gas liquids. We have approximately 1,300 barrels per day of natural gas liquids that we have included in our natural gas volumes in addition to our approximately 1,700 barrels of oil production which we typically report. Proved Reserves Our estimated proved reserves as of December 31, 2011, were 1.3 Tcfe with a pre-tax PV-10 of $1.7 billion calculated pursuant to SEC pricing rules. For 2011, the reference price was $4.12 per Mmbtu for natural gas and $96.19 per Bbl for oil which resulted in an adjusted price of $4.16 per Mmbtu for natural gas and $91.66 per Bbl for oil. Using the average of the ten year futures strip price at December 31, 2011 of $4.94 per Mmbtu for natural gas and $92.72 per Bbl of oil, as adjusted for energy content, quality and basis differentials, our estimated proved reserves would have been 1.5 Tcfe with a pre-tax PV-10 of $2.4 billion. During 2011, we added 201 Bcfe of proved reserves through the drill bit and produced 183 Bcfe, resulting in a production replacement ratio of 110%. Also in 2011, we purchased 62 Bcfe of proved reserves. Revisions due to price decreased proved reserves by 15 Bcfe while performance related revisions further reduced our proved reserves by 62 Bcfe. We had positive reserve revisions in our Haynesville shale, but conventional reserve revisions more than offset the Haynesville shale revisions. In addition, we reclassified 168 Bcfe of conventional proved undeveloped reserves to unproved reserves as a result of the five-year proved undeveloped rule. Our proved reserves grew by 1% from the prior year, adjusted for reclassified reserves, price related revisions and sold reserves. Our proved developed reserves grew by 22% from the prior year, adjusted for price related revisions and sold reserves, and were 74% of our year-end total proved reserves. The following table presents the details of our changes in proved reserves:       EquivalentOilNatural gasnatural gas(Mbbls)(Mmcf)(Mmcfe) Proved Developed Reserves 4,565 955,522 982,912 Proved Undeveloped Reserves 1,789   335,942   346,676   Total 6,354   1,291,464   1,329,588     The changes in reserves for the year are as follows: January 1, 2011 7,358 1,454,953 1,499,101 Purchase of reserves in place - 62,489 62,489 Extensions and discoveries 929 195,565 201,139 Revisions of previous estimates: Reclassification to unproved reserves (1) (182 ) (167,172 ) (168,264 ) Changes in price 100 (15,165 ) (14,565 ) Other factors (1,082 ) (55,341 ) (61,833 ) Sales of reserves in place (28 ) (5,599 ) (5,767 ) Production (741 ) (178,266 ) (182,712 ) December 31, 2011 6,354   1,291,464   1,329,588   (1) Represents Proved Undeveloped Reserves reclassified to unproved pursuant to the five year development rule established by the SEC. This reclassification was a result of decisions not to commit development capital in the current commodity price environment. While these locations qualify as Proved Undeveloped Reserves as they directly offset a proved location, our planned capital programs do not support development at this time. Most of our proved reserves in the Haynesville/Bossier shales are booked in our DeSoto Parish assets. We believe that booking of proved reserves in the Shelby Area and in the Marcellus shale will follow the history of the development of DeSoto Parish. Over a three year period, we transitioned from exploration to testing and delineation and ultimately to development in DeSoto Parish. As such, we booked much of the area on a proved basis at year-end 2010. Our drilling activities during 2011 in the Haynesville/Bossier shales were dominated by our drilling in our DeSoto Parish position, the vast majority of which resulted in converting proved undeveloped reserves into proved developed reserves. Our drilling in the Shelby Area during 2011 was primarily focused on establishing units to hold our acreage and testing completion designs and flowback techniques. In Appalachia, our drilling activities in 2011 were focused on establishing a development program in Northeast Pennsylvania and continuing to appraise our Central Pennsylvania assets. We believe that an analysis of our total proved finding and development costs is most relevant on a three-year basis which represents the historical timeline of our reserve bookings in DeSoto Parish. Our drilling and development spending totaled $1.5 billion from 2009 to 2011 resulting in a finding and development cost of $1.35 per Mcfe. Including revisions other than price, our three-year finding and development cost was $1.41 per Mcfe. Including $132 million of leasehold additions and $178 million of acquisitions, our “all-in” three-year finding and development cost was $1.56 per Mcfe. Adjusting for the benefit of $488 million of BG carry, our “all-in” three-year finding and development cost would have been $1.99 per Mcfe. The following table details the components of our three-year finding and development cost:   2009 through 2011(dollars in thousands, except per Mcfe)Cost   Mmcfe   Per Mcfe Haynesville (1) $ 808,824 861,406 $ 0.94 Marcellus (2)   14,070 20,961   0.67 Total shale 822,894 882,367 0.93 Conventional (3)   237,464 84,118   2.82 Total development 1,060,358 966,485 1.10 Exploratory (4)   406,369 122,337   3.32 Total development and exploration 1,466,727 1,088,822 1.35 Revisions - other than price   - (49,319 ) - Subtotal 1,466,727 1,039,503 1.41 Proved acquisitions 178,342 100,601 1.77 Leasehold additions   132,400 -   - Total $ 1,777,469 1,140,104   1.56   (1) Adjusting for the cumulative benefit of $353 million of BG carry associated with our Haynesville development drilling, our three-year finding and development cost would have been $1.35 Mcfe. (2) Adjusting for the benefit of $14 million of BG carry associated with our Marcellus development drilling, our three-year finding and development cost would have been $1.36 Mcfe. (3) Primarily development of our Permian assets which have high oil and liquids production. (4) Adjusting for the cumulative benefit of $121 million of BG carries in Haynesville and Marcellus exploratory drilling, our three-year finding and development cost would have been $4.31 per Mcfe. During 2011, we added 379 Bcfe to our proved developed reserves resulting in a finding and development cost of $2.21 per Mcfe. Adjusting for the benefit of $66 million of BG carry associated with our proved developed reserve additions, our finding and development cost would have been $2.38 per Mcfe. The following table details the components of our 2011 proved developed additions:   2011(dollars in thousands, except per Mcfe)Cost   Mmcfe   Per Mcfe Haynesville (1) $ 573,080 286,059 $ 2.00 Marcellus (2)   8,167 9,663 0.85 Total shale 581,247 295,722 1.97 Conventional (3)   24,176 6,439 3.75 Total development 605,423 302,161 2.00 Exploratory (4)   230,835 76,749 3.01 Total development and exploration $ 836,258 378,910 2.21   (1) Includes $93 million related to wells that were spud in 2010 and excludes $18 million of costs associated with future proved developed reserve additions. (2) Includes $3 million related to wells that were spud in 2010 and excludes $9 million of costs associated with future proved developed reserve additions. (3) Primarily development of our Permian assets which have high oil and liquids production; excludes $24 million of costs associated with wells already included in proved developed. (4) Includes $7 million related to wells that were spud in 2010 and excludes $32 million of costs associated with future proved developed reserve additions. In our core DeSoto Parish Haynesville position as of December 31, 2011, the average gross EUR for proved developed wells was 6.9 Bcf and an average of 1.5 offsetting proved undeveloped locations for each producing well, having an average gross EUR of 6.6 Bcf. We currently estimate the gross proved EUR per 640-acre unit has increased by 8% from 48.8 Bcf at year end 2010 to 52.8 Bcf at year end 2011. In Northeast Pennsylvania, the average gross EUR from proved developed additions during 2011 was 6.2 Bcf. We had an average of 0.4 offsetting proved undeveloped locations for each producing well, having an average gross EUR of 7.3 Bcf. Financial Data Our consolidated balance sheets as of December 31, 2011 and 2010 and consolidated statements of operations for the three months and years ended December 31, 2011 and 2010, and consolidated statements of cash flows for the years ended December 31, 2011 and 2010, 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 Friday, February 24, 2012 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# 42911255. 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 Thursday, February 23, 2012, after market close. A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., March 9, 2012. Please call (855) 859-2056 and enter conference ID# 42911255 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, as amended, for the year ended December 31, 2010 and after February 24, 2012, our Annual Report on Form 10-K for the year ended December 31, 2011, 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, as amended,for the year ended December 31, 2010 and after February 24, 2012, our Annual Report on Form 10-K for the year ended December 31, 2011, which are, or will be, available on our website at www.excoresources.com under the Investor Relations tab.   EXCO Resources, Inc.Consolidated Balance Sheets     December 31,December 31,(in thousands)20112010   Assets Current assets: Cash and cash equivalents $ 31,997 $ 44,229 Restricted cash 155,925 161,717 Accounts receivable, net: Oil and natural gas 88,518 80,740 Joint interest 170,918 104,358 Interest and other 28,488 35,594 Inventory 8,345 7,876 Derivative financial instruments 164,002 73,176 Other   29,815     12,770   Total current assets   678,008     520,460   Equity investments 302,833 379,001 Oil and natural gas properties (full cost accounting method): Unproved oil and natural gas properties and development costs not being amortized 667,342 599,409 Proved developed and undeveloped oil and natural gas properties 3,392,146 2,370,962 Accumulated depletion   (1,657,165 )   (1,312,216 ) Oil and natural gas properties, net   2,402,323     1,658,155   Gas gathering assets 136,203 157,929 Accumulated depreciation and amortization   (29,104 )   (24,772 ) Gas gathering assets, net   107,099     133,157   Office, field, and other equipment, net 42,384 43,149 Deferred financing costs, net 29,622 30,704 Derivative financial instruments 11,034 23,722 Goodwill 218,256 218,256 Deposits on acquisitions - 464,151 Other assets   28     6,665   Total assets $ 3,791,587   $ 3,477,420       EXCO Resources, Inc.Consolidated Balance Sheets         December 31,December 31,(in thousands, except per share and share data)20112010   Liabilities and shareholders' equity Current liabilities: Accounts payable and accrued liabilities $ 117,968 $ 152,999 Revenues and royalties payable 148,926 108,830 Accrued interest payable 17,973 18,983 Current portion of asset retirement obligations 732 900 Income taxes payable - 211 Derivative financial instruments   1,800     3,775   Total current liabilities   287,399     285,698   Long-term debt 1,887,828 1,588,269 Deferred income taxes - - Derivative financial instruments - 4,200 Asset retirement obligations and other long-term liabilities 58,028 58,701 Commitments and contingencies - - Shareholders' equity: Preferred stock, $0.001 par value; authorized shares - 10,000,000; none issued and outstanding - - Common stock, $0.001 par value; 350,000,000 authorized shares; 217,245,504 shares issued and 216,706,283 shares outstanding at December 31, 2011; 213,736,266 shares issued and 213,197,045 shares outstanding at December 31, 2010 215 214 Additional paid-in capital 3,181,063 3,151,513 Accumulated deficit (1,615,467 ) (1,603,696 ) Treasury stock, at cost; 539,221 shares at December 31, 2011 and December 31, 2010   (7,479 )   (7,479 ) Total shareholders' equity   1,558,332     1,540,552   Total liabilities and shareholders' equity $ 3,791,587   $ 3,477,420             EXCO Resources, Inc.Consolidated Statement of Operations   Three months ended December 31,Year ended December 31,(in thousands, except per share data)2011201020112010Revenues: Oil and natural gas $ 178,871   $ 134,898   $ 754,201   $ 515,226   Costs and expenses: Oil and natural gas operating costs 23,923 20,324 84,766 84,145 Production and ad valorem taxes 5,175 4,638 23,875 24,039 Gathering and transportation 27,812 19,330 86,881 54,877 Depreciation, depletion and amortization 109,123 59,119 362,956 196,963 Write-down of oil and natural gas properties 233,239 - 233,239 - Accretion of discount on asset retirement obligations 924 838 3,652 3,758 General and administrative 28,183 28,795 104,618 105,114 (Gain) loss on divestitures and other operating items   (1,352 )   59,224     23,819     (509,872 ) Total costs and expenses   427,027     192,268     923,806     (40,976 ) Operating income (loss) (248,156 ) (57,370 ) (169,605 ) 556,202 Other income (expense): Interest expense (17,438 ) (11,983 ) (61,023 ) (45,533 ) Gain on derivative financial instruments 88,752 (9,549 ) 219,730 146,516 Other income 233 143 788 327 Equity income (loss)   9,957     3,968     32,706     16,022   Total other income (expense)   81,504     (17,421 )   192,201     117,332   Income (loss) before income taxes (166,652 ) (74,791 ) 22,596 673,534 Income tax expense (benefit)   -     (1,940 )   -     1,608   Net income (loss) $ (166,652 ) $ (72,851 ) $ 22,596   $ 671,926   Earnings per common share: Basic Net income (loss) $ (0.78 ) $ (0.34 ) $ 0.11   $ 3.16   Weighted average common shares outstanding   214,137     212,791     213,908     212,465     Diluted Net income (loss) $ (0.78 ) $ (0.34 ) $ 0.10   $ 3.11   Weighted average common and common equivalent shares outstanding   214,137     212,791     216,705     215,735       EXCO Resources, Inc.Consolidated Statement of Cash Flows           Years Ended December 31,(in thousands)20112010Operating Activities: Net income $ 22,596 $ 671,926 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 362,956 196,963 Share-based compensation 11,012 16,841 Accretion of discount on asset retirement obligations 3,652 3,758 Gain on divestitures (479 ) (528,888 ) Write-down of oil and natural gas properties and other impairment losses on long-lived assets 240,039 - Income from equity investments (32,706 ) (16,022 ) Non-cash change in fair value of derivatives (84,313 ) 68,921 Cash settlements of assumed derivatives - 907 Deferred income taxes - - Amortization of deferred financing costs; discount on the 2018 Notes and premium on the 2011 Notes 9,759 5,014 Effect of changes in: Accounts receivable (79,359 ) (136,417 ) Other current assets (5,961 ) 1,188 Accounts payable and other current liabilities   (18,653 )   55,730   Net cash provided by operating activities   428,543     339,921   Investing Activities: Additions to oil and natural gas properties, gathering systems and equipment (984,085 ) (519,206 ) Property acquisitions (753,286 ) (522,765 ) Restricted cash 5,792 (102,808 ) Deposit on acquisitions 464,151 (464,151 ) Equity investments (13,829 ) (143,740 ) Return of investment in equity investments 125,000 - Proceeds from disposition of property and equipment 449,683 1,044,833 Advances to Appalachia JV (1,707 ) (5,017 ) Other   (1,250 )   -   Net cash provided by (used in) investing activities   (709,531 )   (712,854 ) Financing Activities: Borrowings under credit agreements 706,000 2,072,399 Repayments under credit agreements (407,500 ) (1,970,963 ) Proceeds from issuance of 2018 Notes - 738,975 Repayment of 2011 Notes - (444,720 ) Proceeds from issuance of common stock 12,063 23,024 Payment of common stock dividends (34,238 ) (29,760 ) Payments for common shares repurchased - (7,479 ) Settlements of derivative financial instruments with a financing element - (907 ) Deferred financing costs and other   (7,569 )   (31,814 ) Net cash provided by (used in) financing activities   268,756     348,755   Net increase (decrease) in cash (12,232 ) (24,178 ) Cash at beginning of period   44,229     68,407   Cash at end of period $ 31,997   $ 44,229     Supplemental Cash Flow Information: Cash interest payments $ 78,125   $ 54,523   Income tax payments $ 1,458   $ 5,460   Supplemental non-cash investing and financing activities: Capitalized stock option compensation $ 6,406   $ 6,351   Capitalized interest $ 30,083   $ 20,829   Issuance of common stock for director services $ 70   $ 61       EXCO Resources, Inc.Consolidated EBITDAand adjusted EBITDA reconciliations and statement of cash flow data(Unaudited)   Three months endedTwelve months endedDecember 31,December 31,(in thousands)2011   20102011   2010   Net income (loss) $ (166,652 ) $ (72,851 ) $ 22,596 $ 671,926 Interest expense 17,438 11,983 61,023 45,533 Income tax expense (benefit) - (1,940 ) - 1,608 Depreciation, depletion and amortization   109,123     59,119     362,956     196,963   EBITDA(1)   (40,091 )   (3,689 )   446,575     916,030   Accretion of discount on asset retirement obligations 924 838 3,652 3,758 Non-cash write-down of oil and natural gas properties 233,239 - 233,239 - (Gain) loss on divestitures and non-recurring other operating items 118 54,912 27,660 (513,524 ) Equity method income (9,957 ) (3,968 ) (32,706 ) (16,022 ) Non-cash change in fair value of oil and natural gas derivative financial instruments (36,425 ) 60,344 (84,313 ) 70,939 Gain from early termination of derivative financial instruments - - - (37,936 ) Stock based compensation expense   3,475     5,973     11,012     16,841   Adjusted EBITDA(1) $ 151,283   $ 114,410   $ 605,119   $ 440,086   Interest expense (2) (17,438 ) (11,983 ) (61,023 ) (47,551 ) Income tax benefit (expense) - 1,940 - (1,608 ) Amortization of deferred financing costs, premium on 2011 Notes and discount on 2018 Notes 3,441 1,937 9,759 5,014 Non-recurring other operating items 474 (9,050 ) (21,339 ) (15,364 ) Changes in operating assets and liabilities and other (64,551 ) (33,329 ) (103,973 ) (79,499 ) Gain from early termination of derivative financial instruments - - - 37,936 Settlements of derivative financial instruments with a financing element   -     -     -     907   Net cash provided by operating activities $ 73,209   $ 63,925   $ 428,543   $ 339,921           Three months endedTwelve months endedDecember 31,December 31,(in thousands)2011   20102011   2010   Statement of cash flow data:Cash flow provided by (used in): Operating activities $ 73,209 $ 63,925 $ 428,543 $ 339,921 Investing activities (263,129 ) (668,691 ) (709,531 ) (712,854 ) Financing activities 165,499 597,871 268,756 348,755 Other financial and operating data: EBITDA(1) (40,091 ) (3,689 ) 446,575 916,030 Adjusted EBITDA(1) 151,283 114,410 605,119 440,086   (1) Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude non-cash write-downs of oil and natural gas properties and other asset impairments, gains on divestitures and non-recurring other operating items, including litigation reserves, costs associated with our special committee's review of strategic alternatives, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, gains from early terminations of derivative financial instruments, 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. (2) Excludes non-cash changes in fair value of $2.0 million for the year ended December 31, 2010 for interest rate swaps included in GAAP interest expense. Our interest rate swaps expired on February 14, 2010 and we have not entered into any new interest rate swap agreements since that time. EXCO Resources, Inc.Summary of operating data             Three months endedTwelve months endedDecember 31,%December 31,%2011   2010Change2011   2010Change   Production: Oil (Mbbls) 188 183 3 % 741 688 8 % Natural gas (Mmcf) 49,698 31,094 60 % 178,266 107,878 65 % Oil and natural gas (Mmcfe) 50,826 32,192 58 % 182,712 112,006 63 % Average daily production (Mmcfe) 552 350 58 % 501 307 63 %   Average sales prices (before derivative financial instrument activities): Oil (per Bbl) $ 89.48 $ 81.83 9 % $ 91.01 $ 76.18 19 % Natural gas (per Mcf) 3.26 3.86 -16 % 3.85 4.29 -10 % Total production (per Mcfe) 3.52 4.19 -16 % 4.13 4.60 -10 %   Average costs (per Mcfe): Oil and natural gas operating costs $ 0.47 $ 0.63 -25 % $ 0.46 $ 0.75 -39 % Production and ad valorem taxes 0.10 0.14 -29 % 0.13 0.21 -38 % Gathering and transportation costs 0.55 0.60 -8 % 0.48 0.49 -2 % Depletion 2.07 1.69 22 % 1.89 1.60 18 % Depreciation and amortization 0.08 0.14 -43 % 0.10 0.15 -33 % General and administrative expenses 0.55 0.89 -38 % 0.57 0.94 -39 %   TGGT Holdings, LLCEBITDA and adjusted EBITDA reconciliations   Twelve months endedDecember 31,(in thousands)2011   Equity Income $ 32,706 Amortization of the difference in the historical basis of our contribution to TGGT (1,605 ) Equity loss of other investments   513   EXCO's share of TGGT net income 31,614 BG Group's share of TGGT net income   31,614     TGGT net income $ 63,228 Interest expense 8,776 Margin tax expense 636 Depreciation and amortization   25,453   TGGT EBITDA(1) 98,093 (Gain) loss on divestitures and non-recurring other operating items (2)   13,967   TGGT Adjusted EBITDA(1) $ 112,060   EXCO's share of TGGT Adjusted EBITDA (3) $ 56,030   (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) Reflects costs associated with the impairment of a treating facility that was damaged in an explosion, net of insurance recoveries, and other losses associated with additional asset impairments and asset sales. (3) Represents our 50% equity share in TGGT. EXCO Resources, Inc.Douglas H. Miller, Chairman, 214-368-2084orStephen F. Smith, President, 214-368-2084