Exco Resources (EXCO) 8-K Exco Resources, Inc. Reports Third 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 THIRD QUARTER

2013 RESULTS

DALLAS, TEXAS, October 29, 2013…EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced third quarter results for 2013.

– Adjusted net income, a non-GAAP measure, was $0.04 per diluted share for the third quarter 2013 compared with $0.13 per diluted share for the third quarter 2012. The non-GAAP adjustments include gains from asset sales, non-cash gains or losses from derivative financial instruments, non-cash ceiling test write-downs, asset impairments and other items typically not included by securities analysts in published estimates.

– Adjusted EBITDA for the third quarter 2013 was $108 million compared with $123 million for the third quarter 2012. Adjusted EBITDA increased to $108 million for the third quarter 2013 from $96 million and $90 million for the first and second quarter 2013, respectively. Adjusted EBITDA is a non-GAAP measure and is computed using earnings before interest, taxes, depletion, depreciation and amortization, and is further adjusted using gains from asset sales, ceiling test write-downs, asset impairments and other non-cash income and expense items.

– GAAP results were a net loss of $99 million, or $0.46 per diluted share, for the third quarter 2013 compared with a net loss of $346 million, or $1.62 per diluted share, for the third quarter 2012. The net loss for the third quarter 2013 was primarily due to the impairment of our investment in TGGT and additional costs as a result of the acquisitions of Haynesville and Eagle Ford assets. We recorded an impairment of our investment in TGGT related to the excess of the carrying value over our share of the expected proceeds from the anticipated sale. The significant costs incurred during the quarter related to acquisitions included the acceleration of deferred financing costs, transaction costs and transition services. These acquisitions also resulted in a significant increase to our depletion rate. The third quarter 2012 net loss included a $318 million pre-tax non-cash ceiling test write-down of oil and natural gas properties.

The pro forma operating and financial information for the three and nine months endedSeptember 30, 2013 and 2012 is presented in a supplemental schedule to this press release as if the acquisitions of the Haynesville and Eagle Ford assets from subsidiaries of Chesapeake Energy

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Corporation (Chesapeake) and the formation of the EXCO/HGI Partnership had occurred on January 1, 2012.

– Oil, natural gas and natural gas liquids (NGL) production was 42 Bcfe, or 455 Mmcfe per day, for the third quarter 2013 compared with 47 Bcfe, or 512 Mmcfe per day, in the third quarter 2012. Third quarter 2013 production from the East Texas/North Louisiana region was 340 Mmcfe per day compared with 442 Mmcfe per day in the third quarter 2012. The decrease in production was primarily the result of the contribution of conventional properties to the EXCO/HGI Partnership and normal production declines. These decreases were partially offset by additional production from the acquisition of Haynesville assets from Chesapeake during the third quarter 2013. Our South Texas region includes assets focused on oil production in the Eagle Ford shale and other formations acquired from Chesapeake on July 31, 2013. Production from this region subsequent to the acquisition date averaged approximately 6 Mboe per day. The third quarter 2013 production in the Appalachia region averaged 64 Mmcfe per day compared with 46 Mmcfe per day in the third quarter 2012. The increase in production in the Appalachia region was due to our focus on completion activities in the Marcellus shale which resulted in 39 additional wells being brought on production subsequent to the third quarter 2012. Our proportionate share of production from the EXCO/HGI Partnership was 27 Mmcfe per day in the third quarter 2013.

– Oil, natural gas and NGL revenues, before cash settlements on derivatives, for the third quarter 2013 were $165 million compared with third quarter 2012 revenues of $142 million. Our average sales price per Mcfe increased to $3.95 per Mcfe for the third quarter 2013 from $3.01 per Mcfe for the third quarter 2012. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $176 million, or $4.21 per Mcfe in the third quarter 2013, compared with $192 million, or $4.09 per Mcfe in the third quarter 2012.

– Our direct operating costs were $0.41 per Mcfe for the third quarter 2013 compared with $0.37 per Mcfe in the third quarter 2012. The increase per Mcfe is primarily due to higher operating costs associated with oil production in the South Texas region. We reduced the operating cost per Mcfe in our East Texas/North Louisiana region to $0.15 per Mcfe in the third quarter 2013 from $0.27 per Mcfe in the third quarter 2012. We also reduced our operating costs in the Appalachia region to $0.66 per Mcfe in the third quarter 2013 from $0.84 in the third quarter 2012.

– We closed the acquisition of Haynesville shale assets from Chesapeake on July 12, 2013 for $288 million, after customary preliminary purchase price adjustments. We closed the acquisition of the Eagle Ford assets from Chesapeake on July 31, 2013 for $685 million, after customary preliminary purchase price adjustments. To facilitate the purchase of these assets, we amended our credit agreement which increased our borrowing base to $1.6 billion. The borrowing base of $1.6 billion includes an asset sale requirement of $400 million, which requires mandatory payments from proceeds of asset sales and must be repaid or refinanced by July 31, 2014. The remaining borrowing base of $1.2 billion includes a $300 million term loan. The remaining balance of the asset sale requirement was $269 million as of September 30, 2013.

In connection with the closing of the Eagle Ford assets, we entered into a participation agreement with affiliates of Kohlberg Kravis Roberts & Co. L.P. (KKR) to sell an undivided 50% interest in

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the undeveloped acreage we acquired for $131 million in cash, after preliminary purchase price adjustments. After giving effect to the KKR payment, the credit agreement's initial borrowing base and $400 million asset sale requirement were reduced by $131 million. We will jointly develop the Eagle Ford acreage with KKR under the participation agreement. Details of the acquisitions and terms of the KKR agreement are presented in the "Recent developments" section of this press release.

– On October 16, 2013, EXCO and an affiliate of BG Group, plc (BG Group) entered into a definitive agreement to sell their respective equity interests in TGGT to Azure Midstream Holdings LLC (Azure). We expect to receive approximately $230 million in net cash proceeds at the closing, after expected closing adjustments, fees and transaction expenses. We intend to apply all of the net cash proceeds from the anticipated sale of TGGT in the fourth quarter 2013 to reduce outstanding borrowings under the asset sale requirement of our credit agreement, which will result in a corresponding reduction in our borrowing base. Details of the agreement are presented in the "Recent developments" section of this press release. Following the announcement of the definitive agreement to sell TGGT, Standard and Poor's revised EXCO's outlook to stable from negative. Our 50% share of TGGT's adjusted net income for the third quarter 2013 was $9 million compared with $14 million for the third quarter 2012. Our 50% share of TGGT's adjusted EBITDA was $15 million for the third quarter 2013 compared with $21 million for the third quarter 2012, after adjustments for certain non-cash items.

Douglas H. Miller, EXCO's Chief Executive Officer, commented, “Our acquisitions in the Haynesville and Eagle Ford shales support our strategy to grow in our core areas, add to our oil production, and use our outstanding operating expertise. We have begun our development program in the Eagle Ford through the drilling partnership with KKR. Our early drilling and completion results are meeting our expectations, and we plan to quickly implement a manufacturing program on both the Eagle Ford and Haynesville assets. Additionally, we are pleased we've reached an agreement to sell TGGT and will use the proceeds to reduce debt consistent with our financing strategy on the $1 billion of acquisitions we closed on in July.”

Adjusted 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 the non-GAAP measure of adjusted net income:

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	Three Months Ended												Nine Months Ended
	September 30, 2013						September 30, 2012						September 30, 2013						September 30, 2012
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	(98,651	)				$	(346,174	)				$	145,067					$	(1,124,256	)
Adjustments:
Total net (gain) loss on derivatives	(7,443		)				20,261						(19,175		)				(18,346		)
Cash settlements on derivative financial instruments	10,904						50,725						28,416						162,685
Non-cash write down of oil and natural gas properties	—						318,044						10,707						1,022,709
Adjustments included in equity (income) loss	94,580						2,884						94,950						21,683
(Gain) loss on divestitures and other operating items impacting comparability	2,653						1,103						(178,693		)				9,728
Deferred finance cost amortization acceleration	13,183						—						16,718						3,000
Income taxes on above adjustments (1)	(45,551		)				(157,207		)				18,831						(480,584		)
Adjustment to deferred tax asset valuation allowance (2)	39,460						138,470						(58,027		)				449,702
Total adjustments, net of taxes	107,786						374,280						(86,273		)				1,170,577
Adjusted net income	$	9,135					$	28,106					$	58,794					$	46,321
Net income (loss), GAAP (3)	$	(98,651	)	$	(0.46	)	$	(346,174	)	$	(1.62	)	$	145,067		$	0.68		$	(1,124,256	)	$	(5.25	)
Adjustments shown above (3)	107,786			0.50			374,280			1.75			(86,273		)	(0.40		)	1,170,577			5.47
Dilution attributable to share-based payments (4)	—			—			—			—			—			(0.01		)	—			—
Adjusted net income	$	9,135		$	0.04		$	28,106		$	0.13		$	58,794		$	0.27		$	46,321		$	0.22
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding	215,056						214,301						214,877						214,204
Dilutive stock options	274						—						8						—
Dilutive restricted shares	902						—						310						—
Shares used to compute diluted EPS for adjusted net income	216,232						214,301						215,195						214,204

(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 and dilutive restricted shares calculated in accordance with the treasury stock method.

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Cash flow

Our cash flow from operations before changes in working capital and other operating items impacting comparability was $87 million for the third quarter 2013. We primarily use our cash flow from operations and available borrowing capacity in our credit agreement to fund our drilling and development programs and acquire producing properties.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2013		2012			2013		2012
Cash flow from operations, GAAP	$	52,139	$	134,309		$	223,371	$	414,777
Net change in working capital	31,994		(27,382		)	13,400		(124,316		)
Other operating items impacting comparability	2,769		—			7,773		8,625
Cash flow from operations before changes in working capital and other operating items impacting comparability, non-GAAP measure (1)	$	86,902	$	106,927		$	244,544	$	299,086

(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.

Recent developments

Haynesville shale acquisition

We closed the acquisition of the Haynesville assets from Chesapeake on July 12, 2013 for a purchase price of $288 million, after customary preliminary purchase price adjustments. The acquisition included certain producing and undeveloped oil and natural gas assets located in our core Haynesville shale operating area in Caddo Parish and DeSoto Parish, Louisiana. These properties included Chesapeake's non-operated interests in 170 wells operated by EXCO on approximately 5,600 net acres, and operated interests in 11 producing wells on approximately 4,000 net acres. The acquisition added approximately 55 identified drilling locations in the Haynesville shale formation to our drilling inventory. The Haynesville transaction provides strong base production and additional drilling inventory with upside development opportunities.

Eagle Ford shale acquisition

We closed the acquisition of the Eagle Ford assets from Chesapeake on July 31, 2013, for a purchase price of $685 million, after customary preliminary purchase price adjustments. The acquisition included certain producing and undeveloped oil and natural gas assets in the Eagle Ford shale in the counties of Zavala, Dimmit, La Salle and Frio in South Texas. These properties include operated interests in 120 wells on approximately 55,000 net acres. The acquisition added approximately 300 identified drilling locations to our drilling inventory. In addition, we entered into a farm-out agreement with Chesapeake covering an additional 147,000 net acres near the acquired properties. Pursuant to the terms of the farm-out agreement, Chesapeake retains an overriding royalty interest in wells drilled on acreage covered by the farm-out

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agreement, with an option to convert the overriding royalty interest to a working interest at payout of the well. We believe that additional upside exists in deeper formations such as the Buda and Pearsall, as well as shallow targets in the Austin Chalk and other formations.

KKR Participation Agreement

In connection with closing of the Eagle Ford acquisition, we entered into a participation agreement with KKR (KKR Participation Agreement) and sold an undivided 50% interest in the undeveloped acreage we acquired for approximately $131 million, after preliminary closing adjustments.

The KKR Participation Agreement provides that EXCO and KKR will jointly fund future costs to develop the Eagle Ford assets. With respect to each well drilled, EXCO will assign half of its undivided 50% interest in such well to KKR such that KKR will fund and own 75% of each well drilled and EXCO will fund and own 25% of each well drilled. On a quarterly basis, EXCO and KKR will determine the development plan covering the following twelve months. EXCO is required to offer to purchase KKR's 75% working interest in groups of wells drilled that have been on production for one year. These offers will be made on a quarterly basis for groups of wells at fair market value, as defined in the KKR Participation Agreement, subject to specific well criteria and return hurdles. We are required to make our first offer during the first quarter of 2015 for wells that have been on line for approximately one year.

TGGT sale agreement

On October 16, 2013, EXCO and BG Group entered into a definitive agreement to convey 100% of the equity interest in TGGT to Azure for an aggregate sales price of approximately $910 million, subject to customary purchase price adjustments. The consideration consists of approximately $876 million in cash and an equity interest in Azure valued at approximately $34 million, which will be split equally between EXCO and BG Group. The transaction is expected to close in the fourth quarter 2013. After the payment of TGGT's indebtedness, we expect to receive approximately $230 million in net cash proceeds at the closing, after expected closing adjustments, fees and transaction expenses. The equity interest issued to EXCO will be equal to or less than 4% of the total outstanding equity interests of Azure as of the closing date. We intend to apply all of the cash proceeds from the anticipated sale of TGGT in the fourth quarter of 2013 to reduce outstanding borrowings under the asset sale requirement of our credit agreement, which will result in a corresponding reduction in our borrowing base. We recorded an other than temporary impairment of $92 million to our investment in TGGT during the third quarter 2013 as a result of the carrying value exceeding the current fair value based on our share of the expected proceeds from the anticipated sale.

Operations activity and outlook

We spent $91 million on development and exploitation activities, drilling 18 gross (7.2 net) operated wells and completing 23 gross (12.9 net) operated wells in the three months ended September 30, 2013. In addition, we participated in 2 gross (1.0 net) wells operated by others (OBO) during the third quarter 2013.

As a result of the acquisitions of the Haynesville and Eagle Ford assets from Chesapeake, our board of directors approved an increase to our capital expenditure budget of $77 million for the development of

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these assets. Our actual capital expenditures for the nine months ended September 30, 2013 and our expected capital expenditures for the remainder of 2013 are presented in the following table:

(in thousands)	Q1 2013		Q2 2013		Q3 2013		YTD 2013		Q4 2013 Forecast		Full Year Forecast
Capital expenditures (1):
Development capital	$	58,715	$	48,963	$	91,387	$	199,065	$	84,935	$	284,000
Gas gathering and water pipelines	—		—		141		141		9		150
Lease acquisitions and seismic	—		2,449		8,086		10,535		17,465		28,000
Capitalized interest	5,038		4,779		5,447		15,264		4,736		20,000
Corporate and other	4,596		4,310		4,621		13,527		4,323		17,850
Total	$	68,349	$	60,501	$	109,682	$	238,532	$	111,468	$	350,000

(1) Excludes capital expenditures related to our partnership with HGI.

Haynesville/Bossier Shale

As of September 30, 2013, our Haynesville/Bossier shale operated production was 782 Mmcf per day gross (300 Mmcf per day net) and with the addition of production from our OBO wells, we had 315 Mmcf per day of total net Haynesville/Bossier shale production. We operated three drilling rigs in the play during the third quarter 2013. We currently have 40 units fully developed in the Haynesville shale in DeSoto Parish. Including the 11 sections acquired from Chesapeake, we have an additional 39 units to be developed in our core DeSoto Parish area. We spud 9 gross (5.1 net) operated horizontal wells during the quarter. In total, we have 429 operated horizontal wells and 190 OBO horizontal wells flowing to sales. We are currently evaluating plans to add up to three operated drilling rigs to develop the 11 recently acquired sections from Chesapeake, as well as entering into a drilling partnership to facilitate this development.

We completed and turned to sales 5 gross (2.5 net) operated Haynesville horizontal wells on the last day of the quarter. The average initial production rate from these wells was 10 Mmcf per day with an average 7,500 psi flowing casing pressure on an average 18/64ths choke. This maximum choke size is indicative of our modified restricted choke management program in DeSoto Parish.

We continue to see improvements in our Haynesville drilling times, stimulation costs and overall capital efficiency while maintaining an industry leading safety record. Our current DeSoto Parish well costs are averaging approximately $7.5 million per well and our average spud to rig release time for the full year 2013 is 33.7 days.

South Texas

Our South Texas region includes assets in the Eagle Ford shale and other formations acquired from Chesapeake on July 31, 2013. We operated three drilling rigs and two fracture simulation fleets during the third quarter 2013. We spud 6 gross (1.5 net) wells in our core area in the Eagle Ford shale as part of our joint development program with KKR. We also turned to sales 6 gross (3.9 net) wells in our core area that were spud prior to the acquisition date and not subject to the KKR Participation Agreement. The average initial production rate from the wells turned to sales in our core area was approximately 600 Bbl per day. In addition, we spud 2 gross (0.3 net) wells and turned to sales 7 gross (5.1 net) wells on acreage

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outside of our core area. As of September 30, 2013, our gross operated production in the South Texas region was 15 Mboe per day gross (7.6 Mboe per day net).

During the transition phase, we are focused on completing the wells in inventory, redirecting the drilling campaign to manufacturing mode development, assessing the term acreage expirations, preparing to drill certain appraisal wells, and transitioning operations over to EXCO's shared services model. Our transition process also includes meeting with JV partners, mineral and surface owners, state and local officials, and midstream gas pipeline and oil gathering companies, and conducting contractor safety meetings. We opened a temporary office in Dilley, Texas and will be constructing a permanent office site in Zavala County in the field where our development drilling will be focused. We have acquired modern 3D seismic data over a large portion of our acreage to help assess the subsurface potential of the asset.

There are currently four rigs drilling on the acquired Eagle Ford properties and we are currently evaluating the addition of another rig by the end of 2013. The development program will consist of manufacturing mode drilling, acreage retention drilling and pilot spacing drilling to test spacing between laterals. We expect to realize significant operational efficiencies by moving to a manufacturing mode development program in the play. With KKR, we expect to drill approximately 300 identified locations over a five year period including 30 wells during 2013.

Marcellus Shale

Our gross operated Marcellus shale production at the end of the third quarter 2013 was 174 Mmcf per day (50 Mmcf per day net). Our focus through 2013 has been to complete and turn to sales our remaining drilled well inventory while reducing the size of our drilling program due to low natural gas prices.  In the third quarter 2013, we spud 1 gross (0.3 net) operated appraisal well and completed 5 gross (1.4 net) operated Marcellus wells in Northeast Pennsylvania. Our development planning for 2014 is underway and will be focused on appraisal drilling to delineate more of our acreage base. In addition to the Marcellus shale production in Appalachia, we averaged 34 gross (14 net) operated Mmcfe per day of conventional production in the region.

Permian

In the Permian region, the first two horizontal shale wells covered by a joint development agreement with a partner were spud during the three months ended September 30, 2013. The partner will serve as the operator and expects to run one drilling rig through the remainder of 2013. The partner agreed to fund our share of drilling and completion costs within the joint venture area up to $18.9 million, of which $15.7 million was remaining as of September 30, 2013. We expect this carry to be fully utilized by the end of 2013.

EXCO/HGI Partnership

The following discussion of operating results, capital expenditures and planned operations addresses the EXCO/HGI Partnership in which we own a 25.5% economic interest.

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Permian

During the third quarter 2013, the partnership drilled and completed 2 gross (2.0 net) wells in the Sugg Ranch area. Economics for this drilling activity typically have high rates-of-return driven by oil and NGL content. The partnership expects to run one operated rig intermittently at Sugg Ranch for the remainder of 2013. At the end of the third quarter 2013, production from the 442 partnership wells averaged approximately 3.8 net Mboe per day. This average production rate consisted of 1.2 net Mbbls of oil, 7 net Mmcf of natural gas, and 1.4 net Mbbls of natural gas liquids per day.

East Texas/North Louisiana

The Vernon Field in Jackson Parish, Louisiana is the most significant producing field in this group of assets. At the end of the third quarter 2013, net operated production averaged approximately 42 Mmcfe per day from Vernon Field and approximately 38 Mmcfe per day from other fields in East Texas/ North Louisiana. The primary focus in the East Texas/North Louisiana fields is to minimize our operating expense while maintaining production.

In East Texas/North Louisiana, the EXCO/HGI Partnership currently has 915 wells flowing to sales with a total gross operated production rate of approximately 116 Mmcfe per day (80 Mmcfe per day net). In addition, net production from OBO wells averaged 1.8 Mmcfe per day.

TGGT

In the first nine months of 2013, TGGT continued to reduce its operating expenses through an effective asset optimization program. In addition, TGGT's capital expenditures decreased from $108 million during the nine months ended September 30, 2012 to $22 million during the nine months ended September 30, 2013, primarily due to the completion of major treating projects in 2012 and reductions in drilling activity in 2013. Throughput declined in the third quarter 2013 to 1.1 Bcf per day due to normal production declines and reduced drilling activity in the Haynesville shale.

Financial Data

Our consolidated balance sheets as of September 30, 2013 and December 31, 2012, consolidated statements of operations for the three and nine months ended September 30, 2013 and 2012 and consolidated statements of cash flows for the nine months ended September 30, 2013 and 2012, 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, October 30, 2013 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#77148587. 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, after market close, on EXCO’s website on Tuesday, October 29, 2013. A digital recording will be available starting two hours after the completion of the conference call until November

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13, 2013. Please call (800) 585-8367 and enter conference ID#77148587 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, 2012, filed with the Securities and Exchange Commission, or the SEC, on February 21, 2013 and as amended by Amendment No. 1 to Annual Report on Form 10-K/A on August 30, 2013 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, or the EXCO Resources 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.

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 filings with the commission. 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, 2012, filed with the SEC on February 21, 2013 and as amended by Amendment No. 1 to Annual Report on Form 10-K/A on August 30, 2013 and our other periodic filings with the SEC.

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EXCO Resources, Inc.

Consolidated Balance Sheets

(in thousands)	September 30, 2013			December 31, 2012
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	33,493		$	45,644
Restricted cash	36,137			70,085
Accounts receivable, net:
Oil and natural gas	138,932			84,348
Joint interest	48,453			69,446
Other	17,814			15,053
Inventory	3,757			5,705
Derivative financial instruments	31,575			49,500
Other	15,742			22,085
Total current assets	325,903			361,866
Equity investments	286,142			347,008
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	494,333			470,043
Proved developed and undeveloped oil and natural gas properties	3,571,549			2,715,767
Accumulated depletion	(2,102,595		)	(1,945,565		)
Oil and natural gas properties, net	1,963,287			1,240,245
Gas gathering assets	33,519			130,830
Accumulated depreciation and amortization	(9,905		)	(34,364		)
Gas gathering assets, net	23,614			96,466
Office, field and other equipment, net	16,304			20,725
Deferred financing costs, net	30,489			22,584
Derivative financial instruments	12,908			16,554
Goodwill	163,155			218,256
Other assets	30			28
Total assets	$	2,821,832		$	2,323,732

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EXCO Resources, Inc.

Consolidated Balance Sheets

(in thousands, except per share and share data)	September 30, 2013			December 31, 2012
	(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	197,090		$	83,240
Revenues and royalties payable	145,408			134,066
Accrued interest payable	5,748			17,029
Current portion of asset retirement obligations	191			1,200
Income taxes payable	—			—
Derivative financial instruments	7,414			2,396
Current maturities of long-term debt	272,096			—
Total current liabilities	627,947			237,931
Long-term debt	1,863,529			1,848,972
Deferred income taxes	—			—
Derivative financial instruments	10,407			26,369
Asset retirement obligations and other long-term liabilities	41,299			61,067
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; 219,159,738 shares issued and 218,620,517 shares outstanding at September 30, 2013; 218,126,071 shares issued and 217,586,850 shares outstanding at December 31, 2012	216			215
Additional paid-in capital	3,216,842			3,200,067
Accumulated deficit	(2,930,929		)	(3,043,410		)
Treasury stock, at cost; 539,221 shares at September 30, 2013 and December 31, 2012	(7,479		)	(7,479		)
Total shareholders’ equity	278,650			149,393
Total liabilities and shareholders’ equity	$	2,821,832		$	2,323,732

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EXCO Resources, Inc.

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands, except per share data)	2013			2012			2013			2012
Revenues:
Oil and natural gas	$	165,314		$	141,621		$	453,869		$	394,447
Costs and expenses:
Oil and natural gas operating costs	17,187			17,425			42,706			59,084
Production and ad valorem taxes	6,074			6,689			15,303			20,671
Gathering and transportation	26,665			25,847			74,549			78,183
Depletion, depreciation and amortization	74,499			70,589			163,195			247,508
Write-down of oil and natural gas properties	—			318,044			10,707			1,022,709
Accretion of discount on asset retirement obligations	619			985			1,865			2,896
General and administrative	21,937			22,052			66,495			62,194
(Gain) loss on divestitures and other operating items	2,739			1,011			(179,503		)	9,346
Total costs and expenses	149,720			462,642			195,317			1,502,591
Operating income (loss)	15,594			(321,021		)	258,552			(1,108,144		)
Other income (expense):
Interest expense	(36,474		)	(17,935		)	(71,771		)	(55,068		)
Gain (loss) on derivative financial instruments	7,443			(20,261		)	19,175			18,346
Other income	94			149			340			589
Equity income (loss)	(85,308		)	12,894			(61,229		)	20,021
Total other expense	(114,245		)	(25,153		)	(113,485		)	(16,112		)
Income (loss) before income taxes	(98,651		)	(346,174		)	145,067			(1,124,256		)
Income tax expense	—			—			—			—
Net income (loss)	$	(98,651	)	$	(346,174	)	$	145,067		$	(1,124,256	)
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(0.46	)	$	(1.62	)	$	0.68		$	(5.25	)
Weighted average common shares outstanding	215,056			214,301			214,877			214,204
Diluted:
Net income (loss)	$	(0.46	)	$	(1.62	)	$	0.67		$	(5.25	)
Weighted average common shares and common share equivalents outstanding	215,056			214,301			215,195			214,204

13

EXCO Resources, Inc.

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
(in thousands)	2013			2012
Operating Activities:
Net income (loss)	$	145,067		$	(1,124,256	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	163,195			247,508
Share-based compensation expense	9,493			8,072
Accretion of discount on asset retirement obligations	1,865			2,896
Write-down of oil and natural gas properties	10,707			1,022,709
(Income) loss from equity investments	61,229			(20,021		)
(Gain) loss on derivative financial instruments	(19,175		)	(18,346		)
Cash settlements of derivative financial instruments	28,416			162,685
Deferred income taxes	—			—
Amortization of deferred financing costs and discount on debt issuance	22,440			8,111
(Gain) loss on divestitures	(186,466		)	1,103
Effect of changes in:
Accounts receivable	(32,121		)	133,537
Other current assets	4,879			6,019
Accounts payable and other current liabilities	13,842			(15,240		)
Net cash provided by operating activities	223,371			414,777
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment	(180,603		)	(409,616		)
Property acquisitions	(1,007,362		)	(2,748		)
Equity method investments	(363		)	(12,997		)
Proceeds from disposition of property and equipment	745,733			22,640
Restricted cash	33,948			88,619
Net changes in advances from Appalachia JV	10,055			6,849
Net cash used in investing activities	(398,592		)	(307,253		)
Financing Activities:
Borrowings under credit agreements	1,004,523			53,000
Repayments under credit agreements	(777,470		)	(93,000		)
Proceeds from issuance of common stock	1,712			1,397
Payment of common stock dividends	(32,237		)	(25,740		)
Deferred financing costs and other	(33,458		)	(1,625		)
Net cash provided by (used in) financing activities	163,070			(65,968		)
Net increase (decrease) in cash	(12,151		)	41,556
Cash at beginning of period	45,644			31,997
Cash at end of period	$	33,493		$	73,553

14

Supplemental Cash Flow Information:
Cash interest payments	$	74,949	$	78,447
Income tax payments	—		—
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	$	5,533	$	5,778
Capitalized interest	15,264		18,492
Issuance of common stock for director services	65		561
Accrued restricted stock dividends	349		221
EXCO/HGI Partnership debt upon formation, net	58,613		—

15

EXCO Resources, Inc.

Consolidated EBITDA

And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2013			2012			2013			2012
Net income (loss)	$	(98,651	)	$	(346,174	)	$	145,067		$	(1,124,256	)
Interest expense	36,474			17,935			71,771			55,068
Income tax expense	—			—			—			—
Depletion, depreciation and amortization	74,499			70,589			163,195			247,508
EBITDA(1)	$	12,322		$	(257,650	)	$	380,033		$	(821,680	)
Accretion of discount on asset retirement obligations	619			985			1,865			2,896
Non-cash write down of oil and natural gas properties	—			318,044			10,707			1,022,709
(Gain) loss on divestitures and other operating items impacting comparability	2,653			1,103			(178,693		)	9,728
Equity (income) loss	85,308			(12,894		)	61,229			(20,021		)
Net (gains) losses on derivative financial instruments	(7,443		)	20,261			(19,175		)	(18,346		)
Cash settlements on derivative financial instruments	10,904			50,725			28,416			162,685
Share based compensation expense	3,170			2,617			9,493			8,072
Adjusted EBITDA (1)	$	107,533		$	123,191		$	293,875		$	346,043
Interest expense	(36,474		)	(17,935		)	(71,771		)	(55,068		)
Income tax expense	—			—			—			—
Amortization of deferred financing costs and discount	15,843			1,671			22,440			8,111
Other operating items impacting comparability	(2,769		)	—			(7,773		)	(8,625		)
Changes in working capital	(31,994		)	27,382			(13,400		)	124,316
Net cash provided by operating activities	$	52,139		$	134,309		$	223,371		$	414,777

16

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Statement of cash flow data:
Cash flow provided by (used in):
Operating activities	$	52,139		$	134,309		$	223,371		$	414,777
Investing activities	(881,644		)	(105,642		)	(398,592		)	(307,253		)
Financing activities	815,749			(7,510		)	163,070			(65,968		)
Other financial and operating data:
EBITDA(1)	$	12,322		$	(257,650	)	$	380,033		$	(821,680	)
Adjusted EBITDA(1)	107,533			123,191			293,875			346,043

(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 write-downs 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 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.

17

TGGT Holdings, LLC

EBITDA and Adjusted EBITDA Reconciliation

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Equity income (loss)	$	(85,308	)	$	12,894		$	(61,229	)	$	20,021
Amortization of the difference in the historical basis of our contribution to TGGT	(402		)	(402		)	(1,206		)	(1,206		)
Impairment of equity method investments	91,520			—			91,520			—
Equity (income) loss of other investments	2,063			(1,309		)	2,349			1,285
EXCO's share of TGGT net income	7,873			11,183			31,434			20,100
BG Group's share of TGGT net income	7,873			11,183			31,434			20,100
TGGT net income	15,746			22,366			62,868			40,200
Interest expense	2,949			5,356			9,372			11,913
Margin tax expense	95			32			317			300
Depreciation and amortization	9,020			8,967			26,713			23,790
TGGT EBITDA(1)	27,810			36,721			99,270			76,203
Asset impairments and other operating items impacting comparability	1,377			5,767			2,118			43,365
TGGT Adjusted EBITDA(1)	$	29,187		$	42,488		$	101,388		$	119,568
EXCO's share of TGGT Adjusted EBITDA (2)	$	14,594		$	21,244		$	50,694		$	59,784

(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 other operating items impacting comparability. 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.

18

TGGT Holdings, LLC

Computation of Adjusted Net Income

(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in thousands)	2013			2012		2013		2012
Net income, GAAP	$	15,746		$	22,366	$	62,868	$	40,200
Adjustments:
Loss on asset disposal	—			241		163		1,640
Asset impairment, net of insurance recoveries	(545		)	4,618		702		39,961
Other non-cash items	1,922			908		1,253		1,764
Total adjustments	1,377			5,767		2,118		43,365
Adjusted net income	$	17,123		$	28,133	$	64,986	$	83,565
EXCO's 50% share of TGGT's adjusted net income (1)	$	8,562		$	14,067	$	32,493	$	41,783

(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.

19

EXCO Resources, Inc.

Summary of Operating Data

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,				%		September 30,				%
	2013		2012		Change		2013		2012		Change
Production:
Oil (Mbbls)	383		170		125	%	535		544		(2	)%
Natural gas liquids (Mbbls)	53		129		(59	)%	178		382		(53	)%
Natural gas (Mmcf)	39,268		45,330		(13	)%	116,556		140,484		(17	)%
Total production (Mmcfe) (1)	41,884		47,124		(11	)%	120,834		146,040		(17	)%
Average daily production (Mmcfe)	455		512		(11	)%	443		533		(17	)%
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl)	$	102.60	$	86.87	18	%	$	97.49	$	90.33	8	%
Natural gas liquids (per Bbl)	32.04		38.64		(17	)%	35.12		43.71		(20	)%
Natural gas (per Mcf)	3.17		2.69		18	%	3.39		2.34		45	%
Natural gas equivalent (per Mcfe)	3.95		3.01		31	%	3.76		2.70		39	%
Costs and expenses (per Mcfe):
Oil and natural gas operating costs	$	0.41	$	0.37	11	%	$	0.35	$	0.40	(13	)%
Production and ad valorem taxes	0.15		0.14		7	%	0.13		0.14		(7	)%
Gathering and transportation	0.64		0.55		16	%	0.62		0.54		15	%
Depletion	1.74		1.42		23	%	1.30		1.62		(20	)%
Depreciation and amortization	0.04		0.07		(43	)%	0.05		0.08		(38	)%
General and administrative	0.52		0.47		11	%	0.55		0.43		28	%

20

Selected Pro Forma Financial Information

(Unaudited)

The EXCO/HGI Partnership was formed on February 14, 2013, which resulted in the reduction of our economic interest in certain oil and natural gas properties contributed to the partnership. On March 5, 2013, the EXCO/HGI Partnership purchased the remaining shallow Cotton Valley assets in the East Texas/North Louisiana JV from an affiliate of BG Group. During the three months ended September 30, 2013, we closed the acquisitions of oil and natural gas properties in the Haynesville and Eagle Ford shale formations from Chesapeake. The following table presents selected pro forma operating and financial information for the three and nine months ended September 30, 2013 and 2012 as if these transactions had occurred on January 1, 2012:

21

	Three Months Ended September 30, 2013
(dollars in thousands, except per unit rate)	Historical EXCO		EXCO/HGI pro forma adjustments			Chesapeake Properties pro forma adjustments		Pro forma EXCO
Production:
Total production (Mmcfe)	41,884		—			2,311		44,195
Average production (Mmcfe/d)	455		—			25		480
Revenues:
Oil and natural gas revenues	$	165,314	$	—		$	19,995	$	185,309
Average realized price ($/Mcfe)	3.95		—			8.65		4.19
Expenses:
Direct operating costs	17,187		—			2,466		19,653
Per Mcfe	0.41		—			1.07		0.44
Production and ad valorem taxes	6,074		—			805		6,879
Per Mcfe	0.15		—			0.35		0.16
Gathering and transportation (1)	26,665		—			—		26,665
Per Mcfe	0.64		—			—		0.60
Excess of revenues over operating expenses	$	115,388	$	—		$	16,724	$	132,112
	Three Months Ended September 30, 2012
(dollars in thousands, except per unit rate)	Historical EXCO		EXCO/HGI pro forma adjustments			Chesapeake Properties pro forma adjustments		Pro forma EXCO
Production:
Total production (Mmcfe)	47,124		(6,229		)	13,221		54,116
Average production (Mmcfe/d)	512		(68		)	144		588
Revenues:
Oil and natural gas revenues	$	141,621	$	(27,171	)	$	51,598	$	166,048
Average realized price ($/Mcfe)	3.01		4.36			3.90		3.07
Expenses:
Direct operating costs	17,425		(6,981		)	8,161		18,605
Per Mcfe	0.37		1.12			0.62		0.34
Production and ad valorem taxes	6,689		(3,309		)	2,685		6,065
Per Mcfe	0.14		0.53			0.20		0.11
Gathering and transportation (1)	25,847		(1,826		)	—		24,021
Per Mcfe	0.55		0.29			—		0.44
Excess of revenues over operating expenses	$	91,660	$	(15,055	)	$	40,752	$	117,357

(1) The oil and natural gas revenues for the Chesapeake Properties are presented net of gathering and treating expenses.

22

	Nine Months Ended September 30, 2013
(dollars in thousands, except per unit rate)	Historical EXCO		EXCO/HGI Pro forma adjustments			Chesapeake Properties Pro forma adjustments		Pro forma EXCO
Production:
Total production (Mmcfe)	120,834		(2,705		)	27,279		145,408
Average production (Mmcfe/d)	443		(10		)	100		533
Revenues:
Oil and natural gas revenues	$	453,869	$	(12,657	)	$	150,319	$	591,531
Average realized price ($/Mcfe)	3.76		4.68			5.51		4.07
Expenses:
Direct operating costs	42,706		(3,489		)	22,564		61,781
Per Mcfe	0.35		1.29			0.83		0.42
Production and ad valorem taxes	15,303		(1,545		)	5,965		19,723
Per Mcfe	0.13		0.57			0.22		0.14
Gathering and transportation (1)	74,549		(782		)	—		73,767
Per Mcfe	0.62		0.29			—		0.51
Excess of revenues over operating expenses	$	321,311	$	(6,841	)	$	121,790	$	436,260
	Nine Months Ended September 30, 2012
(dollars in thousands, except per unit rate)	Historical EXCO		EXCO/HGI Pro forma adjustments			Chesapeake Properties Pro forma adjustments		Pro forma EXCO
Production:
Total production (Mmcfe)	146,040		(19,196		)	35,270		162,114
Average production (Mmcfe/d)	533		(70		)	129		592
Revenues:
Oil and natural gas revenues	$	394,447	$	(83,085	)	$	115,170	$	426,532
Average realized price ($/Mcfe)	2.70		4.33			3.27		2.63
Expenses:
Direct operating costs	59,084		(22,816		)	19,596		55,864
Per Mcfe	0.40		1.19			0.56		0.34
Production and ad valorem taxes	20,671		(10,084		)	7,071		17,658
Per Mcfe	0.14		0.53			0.20		0.11
Gathering and transportation (1)	78,183		(6,074		)	—		72,109
Per Mcfe	0.54		0.32			—		0.44
Excess of revenues over operating expenses	$	236,509	$	(44,111	)	$	88,503	$	280,901

(1) The oil and natural gas revenues for the Chesapeake Properties are presented net of gathering and treating expenses.

The pro forma information is not necessarily indicative of what actually would have occurred if the transactions had been completed as of January 1, 2012, nor is it necessarily indicative of future consolidated results of operations.

23