Exco Resources (EXCO) 8-K Exco Resources, Inc. Reports First Quarter 2012 Results

Exhibit 99.1

EXCO Resources, Inc.

12377 Merit Drive, Suite 1700, LB 82, Dallas, Texas 75251

(214) 368-2084 FAX (972) 367-3559

EXCO RESOURCES, INC. REPORTS FIRST QUARTER 2012 RESULTS

DALLAS, TEXAS, May 1, 2012…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced first quarter results for 2012.

• Adjusted net income, a non-GAAP measure adjusting for non-cash gains and losses from derivative financial instruments (derivatives), non-cash ceiling test write-downs and other asset impairments and items typically not included by securities analysts in published estimates, was $0.03 per share for the first quarter 2012.

• GAAP results were a net loss of $1.32 per diluted share for the first quarter 2012. The first quarter 2012 includes a $276 million pre-tax non-cash ceiling test write-down of oil and natural gas properties. In addition, equity earnings in TGGT were negatively impacted by certain asset write-downs.

• Oil and natural gas production was 49 Bcfe, or 533 Mmcfe per day, for the first quarter 2012 compared with 552 Mmcfe per day in the fourth quarter 2011 and 408 Mmcfe per day in the first quarter 2011. Our production increases from 2011 are primarily attributable to volumes from the Haynesville shale. The decline from the fourth quarter 2011 reflects our reduced drilling activity in the Haynesville shale. Year over year production increases in our Appalachia region were more than 30%. Our Permian production was flat with the prior year.

• Oil and natural gas revenues for the first quarter 2012 were $135 million compared with first quarter 2011 revenues of $161 million. Our average sales price per Mcfe decreased by 37% from the prior year resulting in the lower revenues despite a 31% increase in production. When the impacts of cash settlements from our oil and natural gas derivatives are considered, oil and natural gas revenues were $185 million for the first quarter 2012.

• 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 first quarter 2012 was $111 million.

• Our direct operating costs were $0.47 per Mcfe for the first quarter 2012 compared with $0.52 per Mcfe for the first quarter 2011. We are taking significant steps in reducing our operating costs in all of our operating areas in response to the low natural gas price environment. Specific actions implemented during the first quarter 2012 include shutting in certain marginal producing wells, reducing compressor rentals, renegotiating water disposal arrangements and modifying chemical treatment programs.

• TGGT’s average throughput remained in excess of 1.5 Bcf per day during the first quarter 2012, including increased volumes from third-party producers. We use the equity method to account for our investment in TGGT. During the first quarter 2012, our 50% interest in TGGT’s operations was a loss of $7 million using GAAP. The loss included certain asset write-downs and losses from disposal of inventory items of $19 million. Our net share of TGGT’s adjusted net income (a non-GAAP measure) was $11 million compared with first quarter 2011 adjusted net income of $8 million.

Douglas H. Miller, EXCO’s Chief Executive Officer, commented, “During the first quarter 2012, we made significant progress on accomplishing many of our key target actions for the year.

“We continued our very successful development activities in the Haynesville and Marcellus shale areas and met our production goals for the quarter with an average of 533 Mmcfe per day. Operationally, we reduced our company-wide rig count from 23 at year end to 14 at the end of the quarter in response to low natural gas prices. We intend to further decrease our rig count during the remainder of the year and expect to end the year with 8 to 10 rigs. We have also reduced our estimated per well drilling costs in the Haynesville from approximately $9.5 million to $8.5 million through a combination of supplier cost reductions and well design changes. We continued to reduce our operating and general and administrative costs.

“As expected, we completed a redetermination of our borrowing base with our lender group at $1.4 billion, which should provide adequate liquidity for our operations going forward. We will seek to reduce our debt levels through asset sales, including all or part of our midstream assets, and sales or joint ventures of certain of our conventional assets.

“We continue to review and evaluate strategic producing and non-producing property acquisitions in our core areas and are also evaluating potential acquisitions in other basins, particularly those that are oil and liquid prone.

“Although the present natural gas environment is difficult, we are positioned financially and operationally to continue successfully maintaining our significant core asset base and capitalizing on opportunities as they arise.”

Net income

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

2

	Three months ended						Three months ended
	March 31, 2012						March 31, 2011
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	(281,649	)				$	21,941
Adjustments:
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes		(3,720	)					23,514
Non-cash write down of oil and natural gas properties, before taxes		275,864						—
Adjustments included in equity income		18,799						—
Non-recurring other operating items		1,952						2,975
Income taxes on above adjustments (1)		(117,158	)					(10,596	)
Adjustment to deferred tax asset valuation allowance (2)		112,660						(8,776	)
Total adjustments, net of taxes		288,397						7,117
Adjusted net income	$	6,748					$	29,058
Net income (loss), GAAP (3)	$	(281,649	)	$	(1.32	)	$	21,941		$	0.10
Adjustments shown above (3)		288,397			1.35			7,117			0.03
Dilution attributable to stock options (4)		—			—			—			—
Adjusted net income	$	6,748		$	0.03		$	29,058		$	0.13
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding		214,145						213,531
Dilutive stock options		451						3,579
Shares used to compute diluted EPS for adjusted net income		214,596						217,110

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

(2) Deferred tax valuation allowance has been adjusted to reflect the assumed income tax rate of 40% for all periods.

(3) Per share amounts are based on weighted average number of common shares outstanding.

(4) Represents dilution per share attributable to common stock equivalents from in-the-money stock options.

Cash flow

Our cash flow from operations before working capital changes was $95 million for the first quarter 2012. We use our cash flow and available borrowing capacity in our credit agreement to fund our drilling and development programs.

	Three months ended
	March 31,
(in thousands)	2012			2011
Cash flow from operations, GAAP	$	145,123		$	79,073
Net change in working capital		(51,579	)		31,239
Non-recurring other operating items		1,952			2,975
Cash flow from operations before changes in working capital and non-recurring other operating items, non-GAAP measure (1)	$	95,496		$	113,287

(1) Cash flow from operations before working capital changes and non-recurring other operating items are presented because management believes it is a useful financial indicator for companies in our industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company’s ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. 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. Non-recurring other operating items have been excluded as they do not reflect our on-going operating activities.

3

Redetermination of borrowing base

On April 27, 2012, we completed our semi-annual borrowing base redetermination with our banking group. The borrowing base was established at $1.4 billion, with an interest grid of LIBOR plus 175 bps to 275 bps (or ABR plus 75 bps to 175 bps). Our debt to EBITDA covenant was changed to 4.5 to 1.0 from 4.0 to 1.0, effective for the quarter ended March 31, 2012 and thereafter. The amendment also provides for a procedure for sales of oil and natural gas properties or other material assets, including our interest in TGGT, whereby the proceeds from asset sales (over a minimum threshold) will be used to pay down the outstanding debt balance under the credit agreement and will also reduce the borrowing base. The borrowing base reduction will be equal to the borrowing base value assigned to the assets sold (if any) plus cash proceeds in excess of the borrowing base value aggregating up to $200 million. As of April 27, 2012, $1.1 billion was drawn under our credit agreement and we had $156 million of cash, which includes $139 million of restricted cash.

Operations activity and outlook

We spent $142 million on development and exploitation activities, drilling and completing 42 gross (18.4 net) operated wells in the first quarter 2012, compared with 65 gross (23.2 net) operated wells during the fourth quarter 2011. In addition, we participated in 10 gross (1.6 net) wells operated by others (OBO) during the first quarter 2012. We had an overall drilling success rate of 100% for the first quarter 2012. Our total capital expenditures, including leasing and net of acreage reimbursements from BG Group, were approximately $162 million in the first quarter 2012.

Our actual capital expenditures for the quarter ended March 31, 2012 and our projected capital spending for the remainder of 2012 is presented in the following table:

	Three months ended		April - December		Full Year
	March 31,		Forecast		Forecast
(in thousands)	2012		2012		2012
Capital expenditures:
Development capital	$	141,771	$	248,229	$	390,000
Gas gathering and water pipelines		533		9,467		10,000
Lease acquisitions and seismic(1)		5,570		14,430		20,000
Capitalized interest		6,302		18,298		24,600
Corporate and other		7,975		17,425		25,400
Total	$	162,151	$	307,849	$	470,000

(1) Net of acreage reimbursements from BG Group totaling $0.1 million received in Q1 2012

4

Haynesville/Bossier Shale

Our horizontal Haynesville shale development program continues to be a significant asset for EXCO and continues to yield strong results. As of April 16, 2012, our Haynesville/Bossier shale operated production was 1,219 Mmcf per day gross (366.5 Mmcf per day net) and with the addition of net production from our OBO wells, we had 401.0 Mmcf per day of total Haynesville/Bossier shale net production. In response to low natural gas prices, we have made a significant reduction to our drilling program. In 2011 we averaged 22 operated rigs in the Haynesville/Bossier shale throughout the year. We began to reduce our rig count in late 2011 and have further reduced the rig count in the first quarter. We currently have eight active operated rigs drilling in the play and will reduce to seven rigs in May. We will evaluate product pricing and project economics and make further decisions on rig count throughout the year. Our development drilling program for 2012 is focused in DeSoto Parish, Louisiana where we continue our 80-acre spacing manufacturing program. Our assets in San Augustine and Nacogdoches Counties, Texas have been delineated and tested and almost all of our core acreage in that area is held by production. We do not have plans to drill additional wells in the East Texas area in 2012 and are now focused on evaluation and planning for future full field development. During 2012, we plan to drill approximately 68 gross (24.5 net) operated wells in the Haynesville/Bossier shale play with almost all of these wells in DeSoto Parish, Louisiana.

We drilled and completed 30 gross (8.4 net) operated horizontal Haynesville/Bossier wells and participated in 10 gross (1.6 net) OBO Haynesville/Bossier horizontal wells during the first quarter 2012. We utilized an average of 14 operated rigs and spud 23 operated horizontal wells during the quarter. We averaged one OBO rig drilling in the play and spud three OBO wells during the quarter. We currently have no OBO rigs drilling. In total, we have 324 operated horizontal wells and 177 OBO horizontal wells flowing to sales.

The average initial production rate from our operated Haynesville horizontal wells completed in the first quarter 2012 in DeSoto Parish was 13.3 Mmcf per day with an average of 8,250 psi flowing casing pressure on an average 18/64ths choke. This 18/64ths choke size is indicative of our new restricted choke management program we have implemented in DeSoto Parish, based on the strong results we realized in our East Texas area. We believe that the current choke management program will result in a higher estimated ultimate recovery (EUR) per well than our initial choke program.

We have a major cost reduction and efficiency program underway and are beginning to see significant improvements in capital efficiency. Our DeSoto Parish well costs in the fourth quarter 2011 were approximately $9.3 to $9.5 million per well. With the changes implemented to date, our current estimated well cost in the DeSoto Parish area is $8.5 million, approximately $1.0 million or 10% less than actual costs at year end 2011. We are expecting to realize additional improvements in capital efficiency during 2012 and are targeting $8.0 million per well by year end 2012.

5

We completed a significant spacing test in our Shelby Area of East Texas in the first quarter 2012 to fully develop the Haynesville and Bossier shales across two units. EXCO and an offset operator drilled 14 new horizontal wells and one vertical monitor well to test and properly evaluate the Haynesville/Bossier shale well spacing to assess the proper development strategy. All wells were turned to sales late in the first quarter 2011 and were completed on schedule. The peak production rate for the project was 215 Mmcf per day gross with flowing casing pressures of 9,085 psi on average with a restricted choke program. Our plans are to evaluate the performance of this spacing pilot before proceeding with additional development in the East Texas area. By enhancing our understanding of reservoir performance, we plan to maximize the EUR from our drilling and completion programs.

Marcellus Shale

Our current gross Marcellus shale production is approximately 116 Mmcf per day (20.2 Mmcf per day net), which represents an increase of more than 7% since the end of 2011. We have more than 35 Mmcf per day (7.4 Mmcf per day net) of production shut in due primarily to offset drilling and completion activities. We have implemented a development program within our acreage in northeast Pennsylvania and are concluding an appraisal program in central Pennsylvania. We plan to drill 49 gross (12.4 net) operated wells in the Marcellus shale play in our Appalachia region during 2012. Of the 49 wells, 46 gross (11.5 net) will be development wells and 3 gross (0.9 net) will be appraisal wells. Most of our drilling activity will be in Lycoming County, Pennsylvania where we are realizing our best returns in the Marcellus shale. We are currently drilling with three operated rigs in the play. Our net drilling dollars are reduced by the effect of the carry we receive from BG Group. Approximately $29.7 million of the carry remains available to us from BG Group as of March 31, 2012. We expect that the remaining carry will be used in 2012.

During the first quarter 2012, we spud 11 new operated wells and drilled and completed 3 gross (1.2 net) operated wells in the Marcellus shale. These three completed wells included two appraisal wells in Central Pennsylvania and one delineation well in Northeast Pennsylvania. The two Central Pennsylvania appraisal wells are currently awaiting pipeline connections. We are also focused on building our field infrastructure in support of our expected levels of activity. Along with efficiency gains derived from our drilling and completion program, these infrastructure investments are expected to be the primary drivers to reduce our average development well costs.

Permian

We drilled and completed 9 gross (8.8 net) wells in our Sugg Ranch area during the first quarter 2012 with 100% drilling success. We currently are running one operated rig and plan to drill and complete 36 gross (34.9 net) wells in 2012. Our oil production at Sugg Ranch has increased by 4% to approximately 1,700 net barrels per day in the first quarter of 2012 as compared to the fourth quarter of 2011, and economics for this drilling activity typically have rates-of-return in excess of 50%. In addition to the oil production, we also produced approximately 1,300 net barrels of natural gas liquids per day and 5.8 net Mmcf of natural gas per day, resulting in a total of approximately 4,000 barrels per day of net oil equivalent production from our Permian operations.

6

Based on industry results surrounding our Permian acreage position, we are currently evaluating our shale potential. We are drilling a vertical test well and are evaluating core samples. Based on those results, we may spud a horizontal test well during the second quarter of 2012.

Midstream

Our jointly held midstream company, TGGT, had total throughput which averaged approximately 1.5 Bcf per day for the first quarter of 2012. TGGT’s adjusted EBITDA of $34.7 million for the first quarter of 2012 was a 19% increase over TGGT’s adjusted EBITDA for the fourth quarter of 2011.

TGGT installed temporary treating units in the Holly area at its damaged facility from a second quarter 2011 incident and began treating volumes late in the first quarter of 2012. Currently, no Holly volumes are constrained due to treating capacity issues. TGGT is installing permanent treating at its Holly treating locations with start-up planned during the third quarter 2012. For the three months ended March 31, 2012, TGGT recorded an impairment of approximately $35 million of certain assets ($18 million net to us) associated with the installation of temporary treating facilities in response to the May 2011 pipeline incident. After completion of an independent engineering study, the decision was made to activate the permanent facility affected by the incident since that facility had not sustained as much damage as was initially contemplated. The impairment primarily resulted from costs incurred related to temporary treating facilities that were not utilized or determined to have a shorter utilization period than originally anticipated. In addition, lower than expected throughput volumes at the facility as a result of reduced drilling contributed to the impairment.

In our Shelby area, a 20 mile pipeline project and a treating facility will be operational in the second quarter of 2012, which will provide treating capacity of approximately 250 Mmcf per day. Once the Shelby pipeline and the treating facility are operational, TGGT’s major infrastructure development in the Shelby Area will be concluded for 2012.

Financial Data

Our consolidated balance sheets as of March 31, 2012 and December 31, 2011 and consolidated statements of operations for the three months ended March 31, 2012 and 2011, and consolidated statements of cash flows for the three months ended March 31, 2012 and 2011, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release which have not been previously reconciled.

EXCO will host a conference call on Wednesday, May 2, 2012 at 10:00 a.m. (Dallas time) to discuss the contents of this release and respond to questions. Please call (800) 309-5788 if you wish to participate, and ask for the EXCO conference call ID# 70531704. 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, after market close, on EXCO’s website on Tuesday, May 1, 2012.

7

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., May 16, 2012. Please call (800) 585-8367 and enter conference ID# 70531704 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 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 press release and the risk factors included in 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. 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 actually being realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2011, which is available on our website at www.excoresources.com under the Investor Relations tab.

8

EXCO Resources, Inc.

Consolidated balance sheet

	March 31,			December 31,
(in thousands)	2012			2011
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	30,571		$	31,997
Restricted cash		164,042			155,925
Accounts receivable, net:
Oil and natural gas		49,133			88,518
Joint interest		130,183			170,918
Interest and other		28,392			28,488
Inventory		8,101			8,345
Derivative financial instruments		171,182			164,002
Other		21,246			29,815
Total current assets		602,850			678,008
Equity investments		295,064			302,833
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized		623,268			667,342
Proved developed and undeveloped oil and natural gas properties		3,320,977			3,392,146
Accumulated depletion		(1,742,681	)		(1,657,165	)
Oil and natural gas properties, net		2,201,564			2,402,323
Gas gathering assets		136,740			136,203
Accumulated depreciation and amortization		(30,767	)		(29,104	)
Gas gathering assets, net		105,973			107,099
Office, field and other equipment, net		41,228			42,384
Deferred financing costs, net		28,101			29,622
Derivative financial instruments		10,073			11,034
Goodwill		218,256			218,256
Other assets		28			28
Total assets	$	3,503,137		$	3,791,587

9

EXCO Resources, Inc.

Consolidated balance sheet

	March 31,			December 31,
(in thousands, except per share and share data)	2012			2011
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	126,790		$	117,968
Revenues and royalties payable		117,657			148,926
Accrued interest payable		3,713			17,973
Current portion of asset retirement obligations		732			732
Income taxes payable		—			—
Derivative financial instruments		3,447			1,800
Total current liabilities		252,339			287,399
Long-term debt		1,918,106			1,887,828
Deferred income taxes		—			—
Derivative financial instruments		852			—
Asset retirement obligations and other long-term liabilities		59,006			58,028
Commitments and contingencies		—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; issued and outstanding shares - 200,000 presented above none issued and outstanding		—			—
Common stock, $0.001 par value; 350,000,000 authorized shares; 217,197,701 shares issued and 216,658,480 shares outstanding at March 31, 2012; 217,245,504 shares issued and 216,706,283 shares outstanding at December 31, 2011		215			215
Additional paid-in capital		3,185,877			3,181,063
Accumulated deficit		(1,905,779	)		(1,615,467	)
Treasury stock, at cost; 539,221 shares at March 31, 2012 and December 31, 2011		(7,479	)		(7,479	)
Total shareholders’ equity		1,272,834			1,558,332
Total liabilities and shareholders’ equity	$	3,503,137		$	3,791,587

10

EXCO Resources, Inc.

Consolidated statement of operations

(Unaudited)

	Three months ended March 31,
(in thousands, except per share data)	2012			2011
Revenues:
Oil and natural gas	$	134,848		$	161,228
Costs and expenses:
Oil and natural gas operating costs		22,796			19,045
Production and ad valorem taxes		7,193			5,599
Gathering and transportation		26,423			17,286
Depreciation, depletion and amortization		89,582			67,930
Write-down of oil and natural gas properties		275,864			—
Accretion of discount on asset retirement obligations		947			857
General and administrative		21,505			23,423
Other operating items		1,625			2,457
Total costs and expenses		445,935			136,597
Operating income (loss)		(311,087	)		24,631
Other income (expense):
Interest expense		(16,764	)		(14,816	)
Gain on derivative financial instruments		53,865			3,421
Other income		243			160
Equity income (loss)		(7,906	)		8,545
Total other income (expense)		29,438			(2,690	)
Income (loss) before income taxes		(281,649	)		21,941
Income tax expense		—			—
Net income (loss)	$	(281,649	)	$	21,941
Earnings per common share:
Basic:
Net income (loss)	$	(1.32	)	$	0.10
Weighted average common shares outstanding		214,145			213,531
Diluted:
Net income (loss)	$	(1.32	)	$	0.10
Weighted average common and common equivalent shares outstanding		214,145			217,110

11

EXCO Resources, Inc.

Consolidated statement of cash flows

(Unaudited)

	Three months ended March 31,
(in thousands)	2012			2011
Operating Activities:
Net income (loss)	$	(281,649	)	$	21,941
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		89,582			67,930
Share-based compensation expense		2,864			2,668
Accretion of discount on asset retirement obligations		947			857
Write-down of oil and natural gas properties		275,864			—
(Income) loss from equity investments		7,906			(8,545	)
Non-cash change in fair value of derivatives		(3,720	)		23,514
Deferred income taxes		—			—
Amortization of deferred financing costs; discount on the 2018 Notes and premium on the 2011 Notes		1,750			1,947
Effect of changes in:
Accounts receivable		78,796			(15,296	)
Other current assets		1,871			(2,813	)
Accounts payable and other current liabilities		(29,088	)		(13,130	)
Net cash provided by operating activities		145,123			79,073
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment		(169,756	)		(199,610	)
Property acquisitions		(1,402	)		(506,833	)
Equity investments		(137	)		(162	)
Proceeds from disposition of property and equipment		981			259,103
Restricted cash		(8,117	)		11,125
Net changes in advances (to) from Appalachia JV		10,543			(5,063	)
Return of investment in equity investments		—			125,000
Deposit on acquisitions		—			464,151
Other		—			(1,250	)
Net cash provided by (used in) investing activities		(167,888	)		146,461
Financing Activities:
Borrowings under credit agreements		53,000			40,000
Repayments under credit agreements		(23,000	)		(300,000	)
Proceeds from issuance of common stock		2			7,312
Payment of common stock dividends		(8,663	)		(8,547	)
Net cash provided by (used in) financing activities		21,339			(261,235	)
Net decrease in cash		(1,426	)		(35,701	)
Cash at beginning of period		31,997			44,229
Cash at end of period	$	30,571		$	8,528
Supplemental Cash Flow Information:
Cash interest payments	$	34,883		$	32,809
Income tax payments		—		$	—
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation	$	1,931		$	1,380
Capitalized interest	$	6,302		$	7,740
Issuance of common stock for director services	$	17		$	15

12

EXCO Resources, Inc.

Consolidated EBITDA

And adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)

	Three months ended
	March 31,
(in thousands)	2012			2011
Net income (loss)	$	(281,649	)	$	21,941
Interest expense		16,764			14,816
Income tax expense		—			—
Depreciation, depletion and amortization		89,582			67,930
EBITDA(1)		(175,303	)		104,687
Accretion of discount on asset retirement obligations		947			857
Non-cash write down of oil and natural gas properties		275,864			—
Non-recurring other operating items		1,952			2,975
Equity (income ) loss		7,906			(8,545	)
Non-cash change in fair value of derivative financial instruments		(3,720	)		23,514
Stock based compensation expense		2,864			2,668
Adjusted EBITDA (1)	$	110,510		$	126,156
Interest expense		(16,764	)		(14,816	)
Income tax expense		—			—
Amortization of deferred financing costs, premium on the 2011 Notes and discount on the 2018 Notes		1,750			1,947
Deferred income taxes		—			—
Non-recurring other operating items		(1,952	)		(2,975	)
Changes in operating assets and liabilities		51,579			(31,239	)
Net cash provided by operating activities	$	145,123		$	79,073

	Three months ended
	March 31,
(in thousands)	2012			2011
Statement of cash flow data (unaudited):
Cash flow provided by (used in):
Operating activities	$	145,123		$	79,073
Investing activities		(167,888	)		146,461
Financing activities		21,339			(261,235	)
Other financial and operating data:
EBITDA(1)		(175,303	)		104,687
Adjusted EBITDA(1)		110,510			126,156

(1) Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude non-recurring other operating items, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash write-downs of assets, stock-based compensation and income or losses from equity method investments. We have presented EBITDA and Adjusted

13

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.

14

TGGT Holdings, LLC

EBITDA and adjusted EBITDA reconciliation

(Unaudited)

		Three months ended March 31,
(in thousands)		2012			2011
Equity income (loss)		$	(7,906	)	$	8,545
Amortization of the difference in the historical basis of our contribution to TGGT			(402	)		(402	)
Equity loss of other investments	��		879			259
EXCO’s share of TGGT net income (loss)			(7,429	)		8,402
BG Group’s share of TGGT net income			(7,429	)		8,402
TGGT net income (loss)		$	(14,858	)	$	16,804
Interest expense			3,874			1,543
Margin tax expense			238			335
Depreciation and amortization			7,881			5,904
TGGT EBITDA(1)			(2,865	)		24,586
Asset impairments and non-recurring other operating items			37,598			—
TGGT Adjusted EBITDA(1)		$	34,733		$	24,586
EXCO’s share of TGGT Adjusted EBITDA (2)		$	17,367		$	12,293

(1) Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude asset impairments, gains and losses on divestitures and non-recurring other operating items. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. Our computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in our computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by generally accepted accounting principles, or GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of a company’s operating, investing and financing activities. As such, we encourage investors not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures.

(2) Represents our 50% equity share in TGGT.

15

TGGT Holdings, LLC

Computation of adjusted net income

(Unaudited)

	Three months ended March 31,
(in thousands)	2012			2011
Net income (loss), GAAP	$	(14,858	)	$	16,804
Adjustments:
Loss on asset disposal		1,399			—
Asset impairment		35,343			—
Other non-cash items		856			—
Income taxes on above adjustments		—			—
Total adjustments, net of taxes		37,598			—
Adjusted net income	$	22,740		$	16,804
EXCO’s 50% share of TGGT’s adjusted net income (1)	$	11,370		$	8,402

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

16

EXCO Resources, Inc.

Summary of operating data

	Three months ended
	March 31,				%
	2012		2011		Change
Production:
Oil (Mbbls)		192		193		-1	%
Gas (Mmcf)		47,381		35,525		33	%
Oil and natural gas (Mmcfe)		48,533		36,683		32	%
Average daily production (Mmcfe)		533		408		31	%
Average sales prices (before derivativefinancial instrument activities):
Oil (per Bbl)	$	97.14	$	90.01		8	%
Gas (per Mcf)		2.45		4.05		-40	%
Total production (per Mcfe)		2.78		4.40		-37	%
Average costs (per Mcfe):
Oil and natural gas operating costs	$	0.47	$	0.52		-10	%
Production and ad valorem taxes		0.15		0.15		0	%
Gathering and transportation costs		0.54		0.47		15	%
Depletion		1.76		1.73		2	%
Depreciation and amortization		0.08		0.13		-38	%
General and administrative		0.44		0.64		-31	%

17