Exco Resources (EXCO) 8-K Results of Operations and Financial Condition

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

EXCO RESOURCES, INC. REPORTS FOURTH QUARTER AND

FULL YEAR 2011 RESULTS

DALLAS, TEXAS, February 23, 2012 …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.

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• 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.

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“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 ended
	December 31, 2011						December 31, 2010						December 31, 2011						December 31, 2010
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share			Amount			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.

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	Three months ended December 31,					%			Twelve months ended December 31,					%
(in thousands)	2011			2010		change			2011		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:

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	2011 Actual Spending
(in thousands)	Fourth Quarter			Full Year		2012 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

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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.

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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

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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).

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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.

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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:

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	Oil (Mbbls)			Natural gas (Mmcf)			Equivalent natural gas (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:

11

	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:

12

	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 atwww.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,

13

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 atwww.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.

14

EXCO Resources, Inc.

Consolidated Balance Sheets

(in thousands)	December 31, 2011			December 31, 2010
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

15

EXCO Resources, Inc.

Consolidated Balance Sheets

(in thousands, except per share and share data)	December 31, 2011			December 31, 2010
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

16

EXCO Resources, Inc.

Consolidated Statement of Operations

	Three months ended December 31,						Year ended December 31,
(in thousands, except per share data)	2011			2010			2011			2010
Revenues:
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

17

EXCO Resources, Inc.

Consolidated Statement of Cash Flows

	Years Ended December 31,
(in thousands)	2011			2010
Operating 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

18

EXCO Resources, Inc.

Consolidated EBITDA

and adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)

	Three months ended December 31,						Twelve months ended December 31,
(in thousands)	2011			2010			2011			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 ended December 31,						Twelve months ended December 31,
(in thousands)	2011			2010			2011			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

19

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.

20

EXCO Resources, Inc.

Summary of operating data

	Three months ended December 31,				% Change			Twelve months ended December 31,				% Change
	2011		2010					2011		2010
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	%

21

TGGT Holdings, LLC

EBITDA and adjusted EBITDA reconciliation

	Twelve months ended December 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.

22