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

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

2014 RESULTS

DALLAS, TEXAS, April 29, 2014…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced first quarter operating and financial results for 2014.

• Adjusted EBITDA was $112 million for the first quarter 2014, which exceeded the high-end of our guidance.

• Production was 37 Bcfe, or 407 Mmcfe per day, for the first quarter 2014, which exceeded our mid-point guidance.

• Oil and natural gas operating costs and general and administrative costs for the first quarter 2014 were below the low-end of our guidance, reflecting continued fiscal discipline.

• Improved leverage position and reduced indebtedness under our credit agreement by $389 million with proceeds from the rights offering of our common stock, asset sales, and cash flows from operations during the first quarter 2014.

• Increased liquidity through $500 million offering of senior unsecured notes issued in April 2014.

• Drilled 36 gross (10.7 net) and completed 15 gross (3.1 net) operated horizontal shale wells in the first quarter 2014.

Jeff Benjamin, EXCO’s chairman, commented, “We have continued to execute on our strategic objectives including improving our liquidity and maintaining financial flexibility, demonstrating fiscal discipline, efficiently exploiting our current asset base and simplifying our corporate structure. Over the past six months, EXCO has reduced total debt under its credit agreement by approximately $630 million. In addition, the recent $500 million senior unsecured notes offering further enhanced our liquidity and added an eight year term to our capital structure. We are encouraged by the recent improvements in natural gas pricing as well as storage levels and general demand. With our improved balance sheet and continued emphasis on capital discipline, EXCO is well positioned for future growth.”

Financial results

GAAP results were a net loss of $5 million, or $0.02 per diluted share, for the first quarter 2014 compared with a net loss of $123 million, or $0.57 per diluted share, for the fourth quarter 2013. Our GAAP results

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for the first quarter 2014 were positively impacted by higher realized prices; however, this was partially offset by losses on derivative financial instruments. The losses on derivative financial instruments were significantly impacted by unrealized losses due to rising commodity futures prices during the period. The recent improvements to our liquidity allow us more flexibility to retain upside optionality for rising prices in future periods. The net loss for the fourth quarter 2013 was primarily due to the non-cash impairment to our oil and natural gas properties.

Adjusted EBITDA for the first quarter 2014 was $112 million compared with $124 million for the fourth quarter 2013. During 2014, our development program will result in a decrease in our net production volumes while increasing our crude oil production compared to the prior year. This is consistent with our previously disclosed guidance for the first quarter 2014 and full year 2014. Adjusted EBITDA is a non-GAAP measure and is computed using earnings before interest, taxes, depletion, depreciation and amortization, and is further adjusted for gains from asset sales, unrealized gains or losses from derivative financial instruments, impairments of our oil and natural gas properties, other non-cash income and expenses, and other items impacting comparability.

Adjusted net income, a non-GAAP measure, was $0.05 per diluted share for the first quarter 2014 compared with $0.04 per diluted share for the fourth quarter 2013. The non-GAAP adjustments include gains from asset sales, unrealized gains or losses from derivative financial instruments, non-cash asset impairments and other items typically not included by securities analysts in published estimates.

Oil, natural gas and natural gas liquids ("NGL") production was 37 Bcfe, or 407 Mmcfe per day, for the first quarter 2014 compared with 41 Bcfe, or 446 Mmcfe per day, in the fourth quarter 2013. First quarter 2014 production from the East Texas/North Louisiana region was 280 Mmcfe per day compared with 311 Mmcfe per day in the fourth quarter 2013. The decrease in production was primarily the result of natural production declines, timing of wells turned-to-sales and higher downtime. The increase in downtime was the result of well maintenance, offset fracturing activities, and weather related issues. First quarter 2014 production from the South Texas region was 584 Mboe, or 6,500 Boe per day, compared with 656 Mboe, or 7,100 Boe per day, in the fourth quarter 2013. The decrease in production was primarily due to higher downtime as a result of wells shut-in for offset drilling and fracturing activities. Additionally, the decrease in production was a result of a lower working interest in the wells turned-to-sales during the quarter compared to our average working interest for producing wells in the region. The first quarter 2014 production in the Appalachia region was 61 Mmcfe per day compared with 66 Mmcfe per day in the fourth quarter 2013. The decrease in production was due to natural production declines and higher downtime due to freezing issues. Our proportionate share of production from the EXCO/HGI Partnership was 24 Mmcfe per day in the first quarter 2014 compared to 26 Mmcfe per day in the fourth quarter 2013.

Oil, natural gas and NGL revenues for the first quarter 2014 were $198 million compared with $180 million for the fourth quarter 2013. Our average sales price per Mcfe increased to $5.42 per Mcfe for the first quarter 2014 from $4.39 per Mcfe for the fourth quarter 2013. Our average sales price for natural gas during 2014 was positively impacted by higher demand due to lower than average temperatures during the winter season which resulted in significantly lower storage levels compared to historical averages. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $179 million, or $4.88 per Mcfe for the first quarter 2014, compared with $194 million, or $4.73 per Mcfe for the fourth quarter 2013.

Our direct operating costs were $19 million, or $0.51 per Mcfe, for the first quarter 2014 compared with $19 million, or $0.45 per Mcfe, for the fourth quarter 2013. The higher rate per Mcfe was primarily due to the

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decrease in production and higher costs associated with the oil production in the Eagle Ford shale compared to our natural gas production.

Cash flows from operations before changes in working capital and other operating items impacting comparability, a non-GAAP measure, were $94 million for the first quarter 2014 compared with $100 million for the fourth quarter 2013. During the first quarter 2014, we primarily used our cash flows from operations to fund our drilling and development program and repay indebtedness under our credit agreement ("EXCO Resources Credit Agreement").

Recent developments

Rights Offering

The Company closed a rights offering and related private placement of our common stock on January 17, 2014 which resulted in the issuance of 54,574,734 shares for proceeds of $273 million. We used the proceeds to reduce indebtedness under our credit agreement including the remaining indebtedness related to the asset sale requirement as well as a portion of the indebtedness under the revolving commitment.

Permian Basin transaction

On March 24, 2014, we closed a purchase and sale agreement with a private party for the sale of our interest in certain non-operated assets in the Permian Basin including producing wells and undeveloped acreage for approximately $68 million, after final purchase price adjustments. The effective date of the transaction was January 1, 2014. Proceeds from the sale were used to reduce indebtedness under the EXCO Resources Credit Agreement.

2022 Notes

On April 16, 2014, we completed a public offering of $500 million in aggregate principal amount of senior notes due April 15, 2022 ("2022 Notes"). We received net proceeds of $490 million after offering fees and expenses. These notes bear interest at a rate of 8.5% per year, payable on April 15 and October 15 of each year, with payments commencing on October 15, 2014. We used the net proceeds to reduce indebtedness under the EXCO Resources Credit Agreement including the $298 million outstanding principal balance on the term loan and the remaining proceeds were used to reduce a portion of the indebtedness outstanding under the revolving commitment. As a result of this transaction, our unused availability under the EXCO Resources Credit Agreement was $684 million on a pro forma basis as of March 31, 2014. The improvement in our liquidity as a result of this offering enhances our financial flexibility and positions us for future growth.

Operations activity and outlook

We spent $80 million on development activities, drilling 36 gross (10.7 net) operated wells and completing 15 gross (3.1 net) operated horizontal shale wells in the first quarter 2014. We continuously evaluate modifications to our drilling schedule in order to maximize our returns in reaction to commodity prices and industry trends. Our actual capital expenditures for the first quarter 2014 are presented in the following table.

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(in thousands)	First Quarter 2014
Capital expenditures (1):
Development capital expenditures	$	80,198
Lease purchases	1,996
Seismic	8
Field operations, gathering and water pipelines	8,518
Corporate and other	9,317
Total capital expenditures	$	100,037

(1) Excludes capital expenditures related to the EXCO/HGI Partnership, which funded its capital expenditures through internally

generated cash flows and its credit agreement.

East Texas / North Louisiana

In the Haynesville shale during the first quarter 2014, we operated three drilling rigs focused on manufacturing in our core area in DeSoto Parish, Louisiana and two drilling rigs focused on appraisal, testing and delineation in the Shelby area of East Texas. We drilled 13 gross (6.0 net) operated wells during the quarter and completed 2 gross (0.7 net) wells during the quarter. As a result of our multi-well pad drilling and completion operations, we had 10 gross (4.3 net) operated wells in the Haynesville shale that were drilled and waiting on completion at the end of the first quarter 2014 which are expected to be turned-to-sales during the second quarter 2014. In DeSoto Parish, we have 42 developed units and 36 undeveloped units. Our plans for 2014 are to develop seven of these units which include drilling 34 gross (17.3 net) wells. We have also initiated drilling operations on our first cross-unit development in DeSoto Parish that includes drilling 5,000 to 8,000 foot laterals in 5 wells. In the Shelby area, our plans for 2014 include an 8 gross (3.8 net) well drilling program consisting of longer laterals, a modified completion design and a more restricted flowback procedure. We will utilize the results from these wells to determine our future development plans in the Shelby area which includes 290 drilling locations.

We are encouraged by the early results of our base production initiatives which have flattened our decline since we have lowered the line pressure and installed artificial lift. In the first quarter 2014, we initiated a pipeline pressure reduction project by working with our midstream provider and lowered the gathering line pressure from 1,250 psi to 980 psi in a portion of our Holly field in DeSoto Parish. The initial results for the set of wells included in this test show an 8-10% production uplift as a result of the reduction in line pressure, and we will continue to evaluate the long-term impact of the lower line pressure. We are currently studying interim lateral compression options and full field compression options to enhance our base production efficiency.

South Texas

In the Eagle Ford shale, we operated five drilling rigs during the first quarter 2014 focused in our core area in Zavala County, Texas. We drilled 23 gross (4.7 net) operated wells and completed 13 gross (2.4 net) wells in the Eagle Ford shale during the quarter. Our 2014 drilling program consists of manufacturing and testing in the core area and appraisal drilling in the adjacent farmout areas. As part of a participation agreement with a joint venture partner in our core area, our working interest in the wells is approximately 17% prior to the acquisitions beginning in 2015 of our joint venture partner's working interest under the terms of the agreement. As a result of the acquisitions, we anticipate that our working interest will increase to approximately 67%. Our lower initial working interest reduces our net capital and production volumes from these wells in the first year.

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We have realized significant improvements to our drilling performance since we acquired the Eagle Ford assets in 2013. We continue to achieve improved drilling times per well and are currently averaging 13 days from spud to rig release compared to 17 days in 2013. Furthermore, we recently drilled a well in 11.3 days with a measured depth of 14,000 and a 7,100 foot lateral. During the first quarter 2014, our shut-in volumes ranged from 1,650 to 2,500 net Bbl of oil per day due to offset drilling, completion and maintenance activities. This impacted our production during the quarter since we had a higher working interest in the wells shut-in compared to the wells being drilled under the participation agreement. We are working to optimize our drilling and completion schedules to reduce shut-in volumes.

We are also implementing initiatives to optimize and increase the efficiency of our production. We installed 24 pumping units on producing Eagle Ford wells during the first quarter 2014 and have plans to install a total of 90 pumping units for the full year 2014. We have realized 1,600 gross (800 net) Bbl of oil per day production uplift from 39 installations during 2013 and 2014. In order to reduce transportation costs and expenses, we have contracted with a third party to design and operate oil and water gathering lines, centralized production facilities and an oil transport pipeline in our core area. We expect to have our first centralized facility operational during 2014.

Appalachia

In the Appalachia region, we remain focused on base production efficiency from our Marcellus shale and conventional assets. Our production has remained relatively flat despite the challenges of a very cold winter that caused higher than average downtime due to freezing conditions. Our most recent appraisal well in the Northeast Pennsylvania area was turned to sales in fourth quarter 2013 and continues to perform above expectations. This appraisal well is currently flowing 7 Mmcf per day at 1,400 psi on a restricted choke. Our 2014 plans include limited appraisal drilling late in the year targeting the Northeast Pennsylvania area.

Financial Data

Our consolidated balance sheets as of March 31, 2014 and December 31, 2013, consolidated statements of operations for the three months ended March 31, 2014, December 31, 2013 and March 31, 2013 and consolidated statements of cash flows for the three months ended March 31, 2014 and 2013, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release.

EXCO will host a conference call on Wednesday, April 30, 2014 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#24918633. The conference call will also be webcast on EXCO’s website at www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted on EXCO’s website prior to the conference call. A digital recording will be available starting two hours after the completion of the conference call until May 14, 2014. Please call (800) 585-8367 and enter conference ID#24918633 to hear the recording. A digital recording of the conference call will also be available on EXCO’s website.

Additional information about EXCO Resources, Inc. may be obtained by contacting Chris Peracchi, EXCO’s Director of Finance and Investor Relations and Treasurer at EXCO’s headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting EXCO’s website at www.excoresources.com. EXCO’s SEC filings and press releases can be found under the Investor Relations tab.

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We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the cautionary statements and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2013, filed with the Securities and Exchange Commission ("SEC") on February 26, 2014, and our other periodic filings with the SEC.

Our revenues, operating results and financial condition substantially depend on prevailing prices for oil and natural gas and the availability of capital from our credit agreement. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

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EXCO Resources, Inc.

Consolidated Balance Sheets

(in thousands)	March 31, 2014			December 31, 2013
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	94,512		$	50,483
Restricted cash	16,943			20,570
Accounts receivable, net:
Oil and natural gas	147,868			128,352
Joint interest	36,707			70,759
Other	16,543			18,022
Derivative financial instruments	1,080			8,226
Inventory and other	7,699			9,442
Total current assets	321,352			305,854
Equity investments	56,924			57,562
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	392,595			425,307
Proved developed and undeveloped oil and natural gas properties	3,617,215			3,554,210
Accumulated depletion	(2,251,174		)	(2,183,464		)
Oil and natural gas properties, net	1,758,636			1,796,053
Gathering assets	33,605			33,473
Accumulated depreciation and amortization	(10,753		)	(10,338		)
Gathering assets, net	22,852			23,135
Office, field and other equipment, net	26,321			27,204
Deferred financing costs, net	27,242			28,807
Derivative financial instruments	6,007			6,829
Goodwill	163,155			163,155
Other assets	29			29
Total assets	$	2,382,518		$	2,408,628

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EXCO Resources, Inc.

Consolidated Balance Sheets

(in thousands, except per share and share data)	March 31, 2014			December 31, 2013
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	120,272		$	109,217
Revenues and royalties payable	185,744			154,862
Drilling advances	87,776			22,971
Accrued interest payable	3,241			18,144
Current portion of asset retirement obligations	191			191
Income taxes payable	—			—
Derivative financial instruments	31,547			11,919
Current maturities of long-term debt	—			31,866
Total current liabilities	428,771			349,170
Long-term debt	1,499,936			1,858,912
Deferred income taxes	—			—
Derivative financial instruments	5,283			9,671
Asset retirement obligations and other long-term liabilities	43,675			42,970
Commitments and contingencies	—			—
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding	—			—
Common stock, $0.001 par value; 350,000,000 authorized shares; 273,317,397 shares issued and 272,778,176 shares outstanding at March 31, 2014; 218,783,540 shares issued and 218,244,319 shares outstanding at December 31, 2013	270			215
Subscription rights, $0.001 par value; none issued and outstanding at March 31, 2014; 54,574,734 issued and outstanding at December 31, 2013	—			55
Additional paid-in capital	3,494,941			3,219,748
Accumulated deficit	(3,082,879		)	(3,064,634		)
Treasury stock, at cost; 539,221 shares at March 31, 2014 and December 31, 2013	(7,479		)	(7,479		)
Total shareholders’ equity	404,853			147,905
Total liabilities and shareholders’ equity	$	2,382,518		$	2,408,628

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EXCO Resources, Inc.

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended
(in thousands, except per share data)	March 31, 2014			December 31, 2013			March 31, 2013
Revenues:
Total revenues	$	198,472		$	180,440		$	138,223
Costs and expenses:
Oil and natural gas operating costs	18,787			18,571			13,617
Production and ad valorem taxes	7,609			6,668			5,248
Gathering and transportation	24,613			26,096			24,476
Depletion, depreciation and amortization	69,275			82,580			41,308
Impairment of oil and natural gas properties	—			97,839			10,707
Accretion of discount on asset retirement obligations	681			649			690
General and administrative	17,338			25,383			17,984
(Gain) loss on divestitures and other operating items	2,746			1,985			(184,882		)
Total costs and expenses	141,049			259,771			(70,852		)
Operating income (loss)	57,423			(79,331		)	209,075
Other income (expense):
Interest expense, net	(20,164		)	(30,818		)	(20,192		)
Loss on derivative financial instruments	(43,022		)	(19,495		)	(43,514		)
Other income (expense)	46			(1,168		)	88
Equity income	1,111			7,949			12,663
Total other expense	(62,029		)	(43,532		)	(50,955		)
Income (loss) before income taxes	(4,606		)	(122,863		)	158,120
Income tax expense	—			—			—
Net income (loss)	$	(4,606	)	$	(122,863	)	$	158,120
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(0.02	)	$	(0.57	)	$	0.74
Weighted average common shares outstanding	260,716			215,410			214,784
Diluted:
Net income (loss)	$	(0.02	)	$	(0.57	)	$	0.74
Weighted average common shares and common share equivalents outstanding	260,716			215,410			214,861

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EXCO Resources, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended March 31,
(in thousands)	2014			2013
Operating Activities:
Net income (loss)	$	(4,606	)	$	158,120
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	69,275			41,308
Share-based compensation expense	1,507			1,735
Accretion of discount on asset retirement obligations	681			690
Impairment of oil and natural gas properties	—			10,707
Income from equity investments	(1,111		)	(12,663		)
Loss on derivative financial instruments	43,022			43,514
Cash settlements (payments) of derivative financial instruments	(19,810		)	16,718
Amortization of deferred financing costs and discount on debt issuance	2,444			5,113
Gain on divestitures and other non-operating items	—			(187,038		)
Effect of changes in:
Accounts receivable	14,576			8,518
Other current assets	(2,517		)	(1,628		)
Accounts payable and other current liabilities	96,873			(41,880		)
Net cash provided by operating activities	200,334			43,214
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(101,404		)	(72,911		)
Property acquisitions	(426		)	(33,390		)
Proceeds from disposition of property and equipment	76,259			611,203
Equity method investments	1,749			(68		)
Restricted cash	3,627			16,793
Net changes in advances to joint ventures	(3,549		)	3,633
Net cash provided by (used in) investing activities	(23,744		)	525,260
Financing Activities:
Borrowings under credit agreements	—			46,757
Repayments under credit agreements	(391,174		)	(623,266		)
Proceeds from issuance of common stock	272,139			22
Payment of common stock dividends	(13,521		)	(10,739		)
Deferred financing costs and other	(5		)	(246		)
Net cash used in financing activities	(132,561		)	(587,472		)
Net increase (decrease) in cash	44,029			(18,998		)
Cash at beginning of period	50,483			45,644
Cash at end of period	$	94,512		$	26,646
Supplemental Cash Flow Information:
Cash interest payments	$	37,113		$	33,624
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	$	1,485		$	1,527
Capitalized interest	4,790			5,079
Issuance of common stock for director services	69			13
Accrued restricted stock dividends	118			127
EXCO/HGI Partnership debt upon formation, net	—			58,613

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EXCO Resources, Inc.

Consolidated EBITDA

And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data

(Unaudited)

	Three Months Ended
(in thousands)	March 31, 2014			December 31, 2013			March 31, 2013
Net income (loss)	$	(4,606	)	$	(122,863	)	$	158,120
Interest expense	20,164			30,818			20,192
Income tax expense	—			—			—
Depletion, depreciation and amortization	69,275			82,580			41,308
EBITDA(1)	$	84,833		$	(9,465	)	$	219,620
Accretion of discount on asset retirement obligations	681			649			690
Impairment of oil and natural gas properties	—			97,839			10,707
(Gain) loss on divestitures and other items impacting comparability	2,600			8,143			(184,386		)
Equity (income) loss	(1,111		)	(7,949		)	(12,663		)
Net losses on derivative financial instruments	43,022			19,495			43,514
Cash settlements (payments) on derivative financial instruments	(19,810		)	13,703			16,718
Share based compensation expense	1,507			1,255			1,735
Adjusted EBITDA (1)	$	111,722		$	123,670		$	95,935
Interest expense	(20,164		)	(30,818		)	(20,192		)
Income tax expense	—			—			—
Amortization of deferred financing costs and discount	2,444			7,184			5,113
Other operating items impacting comparability	(2,600		)	(6,840		)	(2,652		)
Changes in working capital	108,932			34,067			(34,990		)
Net cash provided by operating activities	$	200,334		$	127,263		$	43,214

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EXCO Resources, Inc.

Consolidated EBITDA

And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data

(Unaudited)

	Three Months Ended
(in thousands)	March 31, 2014			December 31, 2013			March 31, 2013
Statement of cash flow data:
Cash flow provided by (used in):
Operating activities	$	200,334		$	127,263		$	43,214
Investing activities	(23,744		)	146,114			525,260
Financing activities	(132,561		)	(256,387		)	(587,472		)
Other financial and operating data:
EBITDA(1)	$	84,833		$	(9,465	)	$	219,620
Adjusted EBITDA(1)	111,722			123,670			95,935

(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 other operating items impacting comparability, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash impairments of assets, stock-based compensation and income or losses from equity method investments. We have presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, these measures are used in covenant calculations required under our credit agreement, the indenture governing our 7.5% senior notes due September 15, 2018 ("2018 Notes"), and the indenture governing our 8.5% senior notes due April 15, 2022. 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 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. The calculation of EBITDA and Adjusted EBITDA as presented herein differ in certain respects from the calculation of comparable measures in the EXCO Resources Credit Agreement, the indenture governing our 2018 Notes and the indenture governing our 2022 Notes.

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EXCO Resources, Inc.

Consolidated Adjusted Net Income and Adjusted Net Income Reconciliations

(Unaudited)

	Three Months Ended
	March 31, 2014						December 31, 2013						March 31, 2013
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	(4,606	)				$	(122,863	)				$	158,120
Adjustments:
Total net losses on derivatives	43,022						19,495						43,514
Cash receipts (payments) on derivative financial instruments	(19,810		)				13,703						16,718
Impairment of oil and natural gas properties	—						97,839						10,707
Adjustments included in equity (income) loss	(1,749		)				(4,736		)				(286		)
(Gain) loss on divestitures and other items impacting comparability	2,600						8,143						(184,386		)
Deferred finance cost amortization acceleration	372						4,256						3,535
Income taxes on above adjustments (1)	(9,774		)				(55,480		)				44,079
Adjustment to deferred tax asset valuation allowance (2)	1,842						49,145						(63,248		)
Total adjustments, net of taxes	16,503						132,365						(129,367		)
Adjusted net income	$	11,897					$	9,502					28,753
Net income (loss), GAAP (3)	$	(4,606	)	$	(0.02	)	$	(122,863	)	$	(0.57	)	$	158,120		$	0.74
Adjustments shown above (3)	16,503			0.07			132,365			0.61			(129,367		)	(0.60		)
Dilution attributable to share-based payments and rights outstanding (4)	—			—			—			—			—			(0.01		)
Adjusted net income	$	11,897		$	0.05		$	9,502		$	0.04		$	28,753		$	0.13
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding	260,716						215,410						214,784
Dilutive stock options	—						—						5
Dilutive restricted shares	257						327						72
Dilutive subscription rights	—						7,118						—
Shares used to compute diluted EPS for adjusted net income	260,973						222,855						214,861

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

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

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

(4) Represents dilution per share attributable to common share equivalents from in-the-money stock options, dilutive restricted shares and subscription rights calculated in accordance with the treasury stock method.

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EXCO Resources, Inc.

Consolidated Cash Flow from Operations before Working Capital Changes and Other Operating Items Impacting Comparability and Reconciliations

(Unaudited)

	Three Months Ended
(in thousands)	March 31, 2014			December 31, 2013			March 31, 2013
Cash flow from operations, GAAP	$	200,334		$	127,263		$	43,214
Net change in working capital	(108,932		)	(34,067		)	34,990
Other operating items impacting comparability	2,600			6,840			2,652
Cash flow from operations before changes in working capital and other operating items impacting comparability, non-GAAP measure (1)	$	94,002		$	100,036		$	80,856

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

14

EXCO Resources, Inc.

Summary of Operating Data

(Unaudited)

	Three Months Ended				%		Three Months Ended				%
	March 31, 2014		December 31, 2013		Change		March 31, 2014		March 31, 2013		Change
Production:
Oil (Mbbls)	593		653		(9	)%	593		102		481	%
Natural gas liquids (Mbbls)	59		65		(9	)%	59		82		(28	)%
Natural gas (Mmcf)	32,722		36,765		(11	)%	32,722		39,593		(17	)%
Total production (Mmcfe) (1)	36,634		41,073		(11	)%	36,634		40,697		(10	)%
Average daily production (Mmcfe)	407		446		(9	)%	407		452		(10	)%
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	88.25	$	90.79	(3	)%	$	88.25	$	81.71	8	%
Natural gas liquids (per Bbl)	35.92		35.51		1	%	35.92		37.72		(5	)%
Natural gas (per Mcf)	4.40		3.23		36	%	4.40		3.20		38	%
Natural gas equivalent (per Mcfe)	5.42		4.39		23	%	5.42		3.40		59	%
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.51	$	0.45	13	%	$	0.51	$	0.33	55	%
Production and ad valorem taxes	0.21		0.16		31	%	0.21		0.13		62	%
Gathering and transportation	0.67		0.64		5	%	0.67		0.60		12	%
Depletion	1.85		1.97		(6	)%	1.85		0.96		93	%
Depreciation and amortization	0.04		0.04		—	%	0.04		0.06		(33	)%
General and administrative	0.47		0.62		(24	)%	0.47		0.44		7	%

(1) Mmcfe is calculated by converting one barrel of oil or natural gas liquids into six Mcf of natural gas.

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