EXCO RESOURCES INC - FORM 8-K - EX-99.1 - Q3 2015 EARNINGS RELEASE

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Exhibit 99.1

EXCO Resources, Inc.

12377 Merit Drive, Suite 1700, Dallas, Texas 75251

Investor Relations Contact: Chris Peracchi (214) 368-2084

FAX (972) 367-3559

EXCO RESOURCES, INC. REPORTS THIRD QUARTER

2015 RESULTS

DALLAS, TEXAS, October 27, 2015…EXCO Resources, Inc. (NYSE: XCO) (“EXCO” or the "Company") today announced operating and financial results for the third quarter 2015.

2015 Third Quarter Highlights


•	Drilled 9 gross (5.2 net) and turned-to-sales 9 gross (4.6 net) operated horizontal wells in the third quarter 2015, consistent with the capital budget.


•	Produced 340 Mmcfe per day, or 31 Bcfe, for the third quarter 2015, at the low-end of guidance. Production decreased 21 Mmcfe per day, or 6%, from the second quarter 2015, primarily due to the timing of completion activities and higher downtime.


•	Adjusted EBITDA, a non-GAAP measure, was $62 million for the third quarter 2015, 10% below adjusted EBITDA for the second quarter 2015, primarily due to lower commodity prices and production.


•	Cost saving initiatives resulted in gathering and transportation costs below the low-end of guidance, lease operating expenses at the low-end of guidance, and general and administrative costs consistent with the mid-point of guidance.

•

Adjusted net income (loss), a non-GAAP measure, was a net loss of $11 million, or $0.04 per diluted share, and GAAP net income (loss) was a net loss of $355 million, or $1.30 per diluted share, for the third quarter 2015. The GAAP net loss was primarily due to the $339 million impairment of the Company’s oil and natural gas properties pursuant to the ceiling test in accordance with full cost accounting.

•

EXCO executed a series of transactions in October 2015 that enhanced its liquidity and financial flexibility. This includes the issuance of $591 million in senior secured second lien term loans that bear interest at 12.5% per annum. The proceeds were utilized to reduce indebtedness under its credit agreement and repurchase $577 million of unsecured notes at an average price of 51% of the principal amount. These transactions reduced EXCO's consolidated net indebtedness by $270 million and would have resulted in $395 million in liquidity on a pro forma basis if these transactions had occurred on September 30, 2015.

Key Developments

Strategic plan update

EXCO is implementing a transformational strategy that focuses on six core areas: 1) liability management, 2) operational performance, 3) capital deployment, 4) risk management, 5) portfolio repositioning, and 6) performance management. The Company believes the execution of this strategy will create long-term value for its shareholders. The six core areas and the Company's recent progress are detailed below:

Liability management - The Company is focused on improving its capital structure and providing structural liquidity. In October 2015, EXCO executed a series of transactions that resulted in the issuance of senior secured second lien term loans and utilized the proceeds to reduce indebtedness under its credit agreement ("Credit Agreement"), senior unsecured notes due 2018 ("2018 Notes") and senior unsecured notes due 2022 ("2022 Notes"). The Company also amended the Credit Agreement which established a borrowing base of $375 million. These transactions triggered a modification of certain covenants in the Credit Agreement, including a reduction in the interest coverage ratio to at least 1.25x and the elimination of the leverage ratio. These transactions enhanced EXCO's balance sheet and increased its financial flexibility, including the following:


•	Reduced total net debt by $270 million, or 18%;


•	Maintained $234 million of secured debt capacity for future exchanges or issuance of new secured debt;


•	Reduced the principal amount of outstanding senior unsecured notes by $577 million, or 46%;


•	Reduced the nearest unsecured debt maturity, due in 2018, by $376 million, or 50%;


•	Extended weighted average debt maturity from 3.6 to 4.7 years, representing a 30% improvement; and


•	Improved pro forma liquidity by $60 million, or 18%.

In addition, EXCO continued to reduce its costs under commercial contracts and renegotiated a sales contract in South Texas during the third quarter of 2015, which improved its realized price on oil production. The Company remains committed to working with its midstream providers to restructure gathering and transportation contracts, which includes contracts in the East Texas and North Louisiana regions with a significant amount underutilized capacity and fee structures above the current market rates.

Operational performance - The Company's operational team is dedicated to the continuous improvement and innovation of well designs in order to maximize the return on capital. The drilling program in the Shelby area of East Texas continues to achieve strong results in both the Haynesville and Bossier shales as the initial results from most wells have performed above the proved reserve type curves. The Company continues to refine its completion techniques in the region, including recent wells that utilized higher concentrations of proppant. EXCO believes there is further potential for reductions in drilling and completion costs in this region based on modifications to well designs, renegotiated contracts with vendors, and efficiencies as it shifts from an appraisal mode into a development mode.

Capital deployment - EXCO has implemented a disciplined capital allocation approach to ensure the highest and best use of capital. The Company will deploy its capital to incremental wells based on prices, cost and performance and will make real-time decisions to modify its development plans based on returns. EXCO's drilling and completion activities are focused on the Shelby area of East Texas, which are targeting rates of return^(*) in excess of 25%. The Company has suspended its drilling program in the South Texas region due to low oil prices.


4.	Risk management - EXCO utilizes derivative financial instruments to protect returns on the capital deployed and provide additional downside protection on its current base production. The Company entered into additional oil and natural gas derivative contracts during the third quarter 2015 and will continue to evaluate plans to enter into additional derivative contracts based on market conditions.


5.	Portfolio repositioning - The Company is focused on allocating capital to drilling to generate value and increasing its drilling inventory through leasing and acreage acquisitions. EXCO continues to actively locate and evaluate opportunities to add undeveloped locations in core areas that meet its strategic objectives at a low cost that allows the Company to generate accretive returns.


6.	Performance management - The Company plans to rigorously manage to high performance levels to ensure high productivity. The Company is evaluating the results from a recent benchmarking analysis of its performance against a peer group to identify further areas for improvement such as general and administrative costs, lease operating expenses, and drilling and completion costs.

Issuance of Senior Secured Second Lien Term Loans

On October 26, 2015, EXCO closed an agreement with Hamblin Watsa Investment Counsel Ltd. and Fairfax Financial Holdings Ltd. (“Fairfax”) for a $300 million Senior Secured Second Lien Term Loan (the “Fairfax Term Loan”). The Fairfax Term Loan was issued at par, bears interest at a rate of 12.5% per annum and has a five-year maturity. The Company used the proceeds of the Fairfax Term Loan to reduce indebtedness under its Credit Agreement. Fairfax is currently one of EXCO's largest shareholders and their investment in the loan demonstrates confidence in EXCO's ability to execute its strategic improvement plan.

EXCO also closed an agreement with certain unsecured noteholders (the “Noteholders”) pursuant to which the Noteholders are lenders under a new $291 million Senior Secured Second Lien Term Loan (the “Exchange Term Loan”) in exchange for the Company repurchasing $577 million of the Noteholders’ senior unsecured notes, representing an average exchange at 51% of par value. The Exchange Term Loan was issued at par, bears interest at a rate of 12.5% per annum and has a five-year maturity. Specifically, EXCO repurchased $376 million of its 2018 Notes and $201 million of its 2022 Notes. The notes repurchased will be cancelled by the trustee following customary settlement procedures. EXCO granted Fairfax and the Exchange Term Loan lenders a pari-passu second lien security interest in substantially all of its assets under the Fairfax Term Loan and the Exchange Term Loan. The fees and other expenses associated with the issuance of the Fairfax Term Loan and the Exchange Term Loan are estimated to be $15 million.

In connection with these transactions, EXCO amended its Credit Agreement which, among other things, established a borrowing base under the Credit Agreement of $375 million. The next borrowing base redetermination is currently scheduled for March 2016. In addition, the interest coverage ratio was reduced to 1.25x and the leverage ratio was eliminated. These transactions provide the Company with the flexibility to issue up to $109 million in additional secured second lien indebtedness and up to $125 million in secured third lien indebtedness. This available liens capacity allows EXCO to pursue future exchanges or issuances of secured indebtedness.

Proposed reverse stock split

EXCO has called a Special Meeting of Shareholders for November 16, 2015 for its shareholders to consider, among other things, a proposal to grant the Board of Directors authority to effect a reverse share split and proportionally reduce the total number of outstanding common shares that are authorized for issuance. The proposal, if approved by the shareholders, would authorize the Board of Directors to effect a reverse share split at a ratio of up to 1-for-10 common shares, with the decision, timing and exact ratio of the reverse share split to be determined by the Board of Directors in its sole discretion. The proposed reverse share split would affect all shareholders uniformly and will not affect any shareholder's ownership percentage.

Services and investment agreement

On September 8, 2015, EXCO closed the Services and Investment Agreement with Energy Strategic Advisory Services LLC ("ESAS"), a wholly-owned subsidiary of Bluescape Resources Company LLC ("Bluescape"). At the closing, C. John Wilder, Executive Chairman of Bluescape, became the Executive Chairman of EXCO's Board of Directors. On September 8, 2015, ESAS purchased 5,882,353 common shares from EXCO at a price per share of $1.70. In addition, ESAS is obligated to purchase $13.5 million common shares through open market purchases during the one year following the closing, subject to certain extensions and exceptions.

Operational Results

Table 1: Summary of operating activities and operational results

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q3	Fiscal
		9/30/15	6/30/15			9/30/14			9/30/15	9/30/14			2015	2015
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Rig counts (1)	#	4	4	—		8	(50	)	4	9	(56	)	N/A	4

Net wells drilled (1)
North Louisiana	#	—	—	—		8.9	(100	)	1.7	16.9	(90	)	N/A	1.7
East Texas	#	2.4	2.9	(17	)	—	100		7.3	3.8	92		N/A	9.8
South Texas	#	2.8	1.5	87		2.7	4		6.1	11.5	(47	)	N/A	6.1
Appalachia and other	#	—	—	—		—	—		—	—	—		N/A	—
Total net wells drilled	#	5.2	4.4	18		11.6	(55	)	15.1	32.2	(53	)	N/A	17.6

Net wells turned-to-sales (1)
North Louisiana	#	—	1.4	(100	)	3.0	(100	)	11.9	7.7	55		N/A	11.9
East Texas	#	2.8	1.0	180		1.0	180		3.8	2.0	90		N/A	5.8
South Texas	#	1.8	3.3	(45	)	2.9	(38	)	9.2	8.2	12		N/A	11.1
Appalachia and other	#	—	—	—		—	—		—	—	—		N/A	0.5
Total net wells turned-to-sales	#	4.6	5.7	(19	)	6.9	(33	)	24.9	17.9	39		N/A	29.3

Daily production
North Louisiana	Mmcfe/d	197	231	(15	)	217	(9	)	212	237	(11	)	N/A	N/A
East Texas	Mmcfe/d	52	40	30		25	108		46	23	100		N/A	N/A
South Texas	Mmcfe/d	44	43	2		35	26		41	38	8		N/A	N/A
Appalachia and other (2)	Mmcfe/d	47	47	—		81	(42	)	48	85	(44	)	N/A	N/A
Total daily production	Mmcfe/d	340	361	(6	)	358	(5	)	347	383	(9	)	340-350	335-345

Production
Oil	Mbbls	635	594	7		537	18		1,733	1,709	1		640-660	2,300-2,400
Natural gas	Bcf	27.5	29.3	(6	)	29.7	(7	)	84.3	94.2	(11	)	27.4-28.2	108.5-111.5
Total production	Bcfe	31.3	32.9	(5	)	33.0	(5	)	94.7	104.5	(9	)	31.3-32.2	122.3-125.9

Capital Expenditures	$MM	64	75	(15	)	104	(38	)	242	303	(20	)	N/A	295-305


(1)	Includes rigs and wells operated by EXCO and excludes rigs and wells operated by others.


(2)	Includes 25 Mmcfe/d of production from Compass Production Partners, LP ("Compass") for both the three and nine months ended September 30, 2014, respectively. EXCO sold its interest in Compass on October 31, 2014.

North Louisiana

Highlights:


•	Produced 197 Mmcfe per day, a decrease of 34 Mmcfe per day, or 15%, from the second quarter 2015 and a decrease of 20 Mmcfe per day, or 9%, from the third quarter 2014.

EXCO’s decrease in production compared to the second quarter 2015 was primarily the result of normal production declines. The Company entered 2015 with three operated rigs drilling in this region and subsequently moved these rigs to the Shelby area of East Texas. EXCO does not have plans for further development in this region during the remainder of 2015. EXCO is analyzing data and assessing potential modifications to its Haynesville shale well design in this region, which includes enhanced completion methods that have proven to be successful in its East Texas region, including the use of more proppant, modified well spacing and longer laterals. These initiatives have the potential to increase the rates of return and EXCO is currently evaluating plans to drill wells featuring these new completion techniques during 2016.

East Texas

Highlights:


•	Produced 52 Mmcfe per day, an increase of 12 Mmcfe per day, or 30%, from the second quarter 2015 and an increase of 27 Mmcfe per day, or 108%, from the third quarter 2014.


•	Drilled 5 gross (2.4 net) operated horizontal Haynesville and Bossier wells in the Shelby area and turned-to-sales 6 gross (2.8 net) wells in the Haynesville and Bossier shales in the Shelby area.


•	Enhanced completion methods yielded strong results above the current proved reserve type curves.

EXCO’s increase in production compared to the second quarter 2015 was primarily the result of additional wells turned-to-sales. Development included 3 rigs that drilled 4 gross (1.9 net) wells in the Haynesville shale and 1 gross (0.5 net) well in the Bossier shale. The wells turned-to-sales included 2 gross (0.9 net) wells in the Haynesville shale and 4 gross (1.9 net) wells in the Bossier shale. EXCO continues to pursue further reductions in drilling and completion costs including renegotiating rig and completion service contracts, as well as modifications to its well design. EXCO recently renegotiated a rig contract that resulted in a reduction in the day rate of 27%. The Company achieved improved drilling times during the third quarter 2015 including drilling a Haynesville shale well in 35 days to a total measured depth of 19,860 feet. In addition, EXCO's development of this region will allow it to realize economies of scale and increase drilling efficiency as the Company moves from an appraisal mode to a manufacturing mode. This includes reductions in road and location costs through the utilization of multi-well pad sites and lower mobilization costs due to closer proximity between well sites. The Company believes these initiatives will allow it to reduce future drilling and completion costs per well by 10% compared to the average for 2015, standardized for lateral length and proppant levels.

EXCO recently completed a Haynesville shale well in Nacogdoches County, Texas with a total measured depth of 21,289 feet, the longest in the Company's history. The well has performed above expectations with an initial production rate of 13.1 Mmcfe per day on a 17/64th restricted choke with a flowing tubing pressure of 9,807 psi. The strong results of this well could unlock further upside as it is located in the predominantly undeveloped southern area of the Company's East Texas position.

The wells turned-to-sales in this region during 2015 featured enhanced completion methods that have continued to yield strong results. These methods have included the use of more than 2,700 lbs of proppant per lateral foot on certain wells. The increased use of proppant is expected to generate a higher EUR as a result of improved contact and conductivity with the reservoir. The initial results for the average of the wells turned-to-sales in this region during 2015 have outperformed the proved reserve type curve based on an EUR of 1.5 Bcf per 1,000 lateral feet for Haynesville shale wells and 1.3 Bcf per 1,000 lateral feet for Bossier shale wells. EXCO also utilized longer laterals for its wells drilled in 2015, averaging over 7,000 feet.

The East Texas region is the primary focus of EXCO’s 2015 development program, which includes 3 rigs for the remainder of 2015. This will allow the Company to drill 6 gross (2.5 net) operated horizontal wells and turn-to-sales 4 gross (2.0 net) wells during the remainder of 2015. EXCO is targeting a rate of return^(*) of approximately 25% to 30% for the wells drilled in this region during the remainder of 2015.

South Texas

Highlights:


•	Produced 7.3 Mboe per day, an increase of 0.1 Mboe per day, or 2%, from the second quarter 2015 and an increase of 1.5 Mboe per day, or 26%, from the third quarter 2014.


•	Drilled 4 gross (2.8 net) operated horizontal wells and turned-to-sales 3 gross (1.8 net) operated horizontal wells.


•	Improved cost structure through renegotiated sales contract and substantial reductions in drilling and completion costs per well.


•	Suspended development program due to low oil prices in the fourth quarter 2015 in order to redeploy capital to other regions with higher rates of return.

EXCO’s increase in production compared to the second quarter 2015 was primarily due to the timing of completion activities and lower downtime. The decrease in downtime was due to more efficient field scheduling of activities and

lower shut-in volumes due to offset frac activities. Development included 2 gross (0.8 net) wells drilled and 2 gross (0.8 net) wells turned-to-sales in the Eagle Ford shale. The wells turned-to-sales in the Eagle Ford shale during the third quarter 2015 averaged initial production rates of 770 Bbls per day. EXCO averaged 11.2 days to drill these wells with an average total measured depth of 15,900 feet and was able to extend the lateral length up to 8,800 feet at an average cost of approximately $5.5 million per well.

Development in the Buda formation included 2 gross (2.0 net) wells drilled and 1 gross (1.0 net) well turned-to-sales. The Company turned-to-sales its third operated Buda well at an estimated cost of $2.6 million. The Company has completed 3 gross (2.4 net) operated Buda wells as of the third quarter 2015, which averaged maximum initial production rates of approximately 450 Bbls of oil per day. In addition, EXCO's first operated Buda well had cumulative production of 86 Mbbls in its first eight months of production. EXCO remains positive on its Buda position as it recently participated in a well adjacent to its acreage that had a maximum initial production of 658 Bbls of oil per day.

EXCO successfully renegotiated a sales contract in this region which improved EXCO's net realized price for the related oil production and resulted in improved oil price differentials below low-end of guidance for the quarter. In addition, a third-party pipeline became operational during third quarter 2015 that will result in a higher realized price and improve the efficiency of production in the region.

As a result of continued depressed oil prices, EXCO has suspended its development program in the South Texas region for the remainder of 2015. The Company's acreage in the South Texas region is approximately 81% held-by-production, which allows EXCO flexibility in the timing of development of this region.

Appalachia

Highlights:


•	Produced 47 Mmcfe per day, consistent with the second quarter 2015 and a decrease of 9 Mmcfe per day, or 16%, from the third quarter 2014.

EXCO’s production from the third quarter 2015 was consistent with the prior quarter as normal production declines were offset by lower downtime. The lower downtime was due to a pipeline disruption in the second quarter which resulted in wells shut-in while the pipeline was repaired. EXCO's plans for the remainder of 2015 include turning-to-sales 1 gross (0.5 net) well that is awaiting gathering lines that are currently being constructed. The Company's position in the Marcellus shale requires low maintenance capital and approximately 82% of the acreage is held-by-production.


(*)	Rates of return are based on NYMEX futures prices as of September 30, 2015, including natural gas prices per Mmbtu of $2.62 for 2015, $2.81 for 2016, $2.99 for 2017, $3.05 for 2018, $3.11 for 2019, $3.21 for 2020 and $3.50 thereafter, and oil prices per Bbl of $45.70 for 2015, $49.23 for 2016, $52.74 for 2017, $55.19 for 2018, $56.97 for 2019, $58.18 for 2020 and $62.50 thereafter.



Financial Results

Table 2: Summary of operational earnings

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Q3	Fiscal
		9/30/15		6/30/15				9/30/14				9/30/15		9/30/14				2015	2015
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Guidance	Guidance
Operating revenues
Oil revenues	$MM	27		32		(16	)	51		(47	)	80		159		(50	)	N/A	N/A
Natural gas revenues	$MM	56		62		(10	)	100		(44	)	184		373		(51	)	N/A	N/A
Total revenues	$MM	84		94		(11	)	151		(44	)	264		532		(50	)	N/A	N/A
Realized oil prices	$/Bbl	43.22		53.11		(19	)	94.50		(54	)	46.09		93.11		(50	)	N/A	N/A
Oil price differentials	$/Bbl	(3.37	)	(4.65	)	(28	)	(3.46	)	(3	)	(4.85	)	(6.75	)	(28	)	(4.00-6.00)	(4.00-6.00)
Realized gas prices	$/Mcf	2.04		2.12		(4	)	3.37		(39	)	2.18		3.96		(45	)	N/A	N/A
Gas price differentials	$/Mcf	(0.73	)	(0.52	)	40		(0.70	)	4		(0.61	)	(0.60	)	2		(0.50-0.60)	(0.55-0.65)

Derivative financial instruments
Cash settlements (payments)	$MM	32		29		10		2		N/M		89		(32	)	(378	)	N/A	N/A
Cash settlements (payments)	$/Mcfe	1.02		0.89		15		0.07		N/M		0.94		(0.31	)	(403	)	N/A	N/A

Costs and expenses
Oil and natural gas operating costs	$MM	13		14		(7	)	14		(7	)	42		49		(14	)	N/A	N/A
Production and ad valorem taxes	$MM	6		6		—		8		(25	)	16		23		(30	)	N/A	N/A
Gathering and transportation	$MM	24		25		(4	)	26		(8	)	74		76		(3	)	N/A	N/A
Oil and natural gas operating costs	$/Mcfe	0.40		0.43		(7	)	0.43		(7	)	0.44		0.47		(6	)	0.40-0.45	0.40-0.45
Production and ad valorem taxes	$/Mcfe	0.19		0.17		12		0.24		(21	)	0.17		0.22		(23	)	0.15-0.20	0.15-0.20
Gathering and transportation	$/Mcfe	0.76		0.75		1		0.78		(3	)	0.78		0.73		7		0.80-0.85	0.80-0.85
General and administrative (1)	$MM	12		11		9		13		(8	)	37		47		(21	)	11-13	48-52

Operational earnings
Adjusted EBITDA (2)	$MM	62		69		(10	)	94		(34	)	189		311		(39	)	N/A	N/A
GAAP net income (loss)	$MM	(355	)	(454	)	(22	)	42		(945	)	(1,127	)	39		N/M		N/A	N/A
Adjusted net income (loss) (2)	$MM	(11	)	(12	)	(8	)	2		(650	)	(42	)	21		(300	)	N/A	N/A
GAAP diluted shares outstanding	MM	273		272		—		272		—		272		268		1		N/A	N/A
Adjusted diluted shares outstanding	MM	273		272		—		272		—		272		268		1		N/A	N/A
GAAP diluted EPS	$/Share	(1.30	)	(1.67	)	(22	)	0.15		(967	)	(4.14	)	0.15		N/M		N/A	N/A
Adjusted diluted EPS	$/Share	(0.04	)	(0.05	)	(20	)	0.01		(500	)	(0.15	)	0.08		(288	)	N/A	N/A


(1)	Excludes equity-based compensation expenses of $0.9 million, $1.4 million and $1.1 million for the three months ended September 30, 2015, June 30, 2015 and September 30, 2014, respectively, and $4.0 million and $4.4 million for the nine months ended September 30, 2015 and 2014, respectively.


(2)	Adjusted EBITDA and Adjusted net income (loss) are non-GAAP measures. See Financial Data section for definitions and reconciliations.

EXCO’s decrease in adjusted EBITDA compared to the second quarter 2015 was primarily due to lower revenues as a result of lower realized oil and natural gas prices and lower natural gas production. The decrease in market prices for oil was partially offset by improved differentials as a result of a renegotiated sales contract in the South Texas region. The decrease in realized natural gas prices was driven by higher differentials on recently turned-to-sales wells that EXCO does not operate in the North Louisiana region and wider differentials in the Appalachia region. The GAAP net loss in each quarter of 2015 was primarily due to impairments of the Company’s oil and natural gas properties pursuant to the ceiling test in accordance with full cost accounting.

EXCO executed on its commitment to fiscal discipline during the third quarter 2015, as evidenced by gathering and transportation below the low-end of guidance and operating costs at low-end of guidance. EXCO has implemented several initiatives to reduce its general and administrative costs, including reductions in its workforce during the second quarter 2014 and first quarter 2015, which resulted in a decrease of 21% for the year-to-date 2015 compared to the same period in 2014.

Cash Flow Results

Table 3: Summary of key cash flow items

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Q3	Fiscal
		9/30/15		6/30/15				9/30/14				9/30/15		9/30/14				2015	2015
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Guidance	Guidance
Cash flow provided by (used in)
Operating activities	$MM	19		52		(63	)	90		(79	)	127		358		(65	)	N/A	N/A
Investing activities	$MM	(63	)	(72	)	(13	)	(112	)	(44	)	(256	)	(237	)	8		N/A	N/A
Financing activities	$MM	15		45		(67	)	24		(38	)	103		(124	)	(183	)	N/A	N/A
Net increase (decrease) in cash	$MM	(29	)	24		(221	)	2		N/M		(26	)	(3	)	767		N/A	N/A

Other key cash flow items
Adjusted operating cash flow (1)	$MM	38		45		(16	)	72		(47	)	119		250		(52	)	N/A	N/A
Free cash flow (1)	$MM	(46	)	(32	)	44		(10	)	360		(143	)	61		(334	)	N/A	N/A


(1)	Adjusted operating cash flow and Free cash flow are non-GAAP measures. See Financial Data section for definitions and reconciliations.

EXCO's decrease in operating cash flows compared to the second quarter 2015 was primarily the result of lower revenues and less favorable working capital conversions. During the third quarter 2015, EXCO primarily used its cash flows from operations to fund drilling and development. The decrease in cash used in investing activities in the third quarter 2015 compared to the second quarter 2015 was primarily due to lower drilling and completion activity in the South Texas region. Financing activities in the third quarter 2015 primarily consisted of borrowings under the Credit Agreement and proceeds from issuance of common shares to ESAS.

Liquidity Results

Table 4: Financial flexibility measures

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q3	Fiscal
		9/30/15	6/30/15			9/30/14			9/30/15	9/30/14			2015	2015
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Cash (1)	$MM	42	67	(37	)	65	(35	)	42	65	(35	)	N/A	N/A
Gross debt (2)	$MM	1,550	1,542	1		1,472	5		1,550	1,472	5		N/A	N/A
Net debt	$MM	1,508	1,475	2		1,407	7		1,508	1,407	7		N/A	N/A
Adjusted EBITDA (3)	$MM	62	69	(10	)	94	(34	)	189	311	(39	)	N/A	N/A
Cash interest expenses (4)	$MM	27	27	—		26	4		80	76	5		26-27	109-114
Adjusted EBITDA/Interest (5)	x	2.30	2.56	(10	)	3.62	(36	)	2.36	4.09	(42	)	N/A	N/A
Secured debt/LTM Adjusted EBITDA (5)	x	1.11	0.97	14		0.51	118		1.11	0.51	118		N/A	N/A
Net debt/LTM Adjusted EBITDA	x	5.59	4.90	14		3.23	73		5.59	3.23	73		N/A	N/A


(1)	Includes restricted cash of $21 million, $18 million and $22 million as of September 30, 2015, June 30, 2015 and September 30, 2014, respectively.


(2)	Excludes unamortized discount of $5 million, $5 million and $6 million as of September 30, 2015, June 30, 2015 and September 30, 2014, respectively.


(3)	Adjusted EBITDA is a non-GAAP measure. See Financial Data section for definition and reconciliation.


(4)	Cash interest expenses exclude the amortization of debt issuance costs, discount on notes and capitalized interest.


(5)	These ratios differ in certain respects from the calculations of comparable measures in the Credit Agreement. As of September 30, 2015, the ratio of consolidated EBITDAX to consolidated interest expense (as defined in the agreement) was 2.6 to 1.0 and the ratio of secured indebtedness to consolidated EBITDAX (as defined in the agreement) was 1.1 to 1.0.

Table 5: Liquidity schedule

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q3	Fiscal
		9/30/15	6/30/15			9/30/14			9/30/15	9/30/14			2015	2015
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Borrowing base on revolver	$MM	600	725	(17	)	875	(31	)	600	875	(31	)	N/A	N/A
Amount drawn on revolver	$MM	300	292	3		222	35		300	222	35		N/A	N/A
Letters of credit	$MM	7	7	—		7	—		7	7	—		N/A	N/A
Available for borrowing	$MM	293	426	(31	)	646	(55	)	293	646	(55	)	N/A	N/A
Cash (1)	$MM	42	67	(37	)	65	(35	)	42	65	(35	)	N/A	N/A
Liquidity (2)	$MM	335	493	(32	)	711	(53	)	335	711	(53	)	N/A	N/A


(1)	Includes restricted cash of $21 million, $18 million and $22 million as of September 30, 2015, June 30, 2015 and September 30, 2014, respectively.


(2)	Liquidity is calculated as the unused borrowing base under the Credit Agreement plus cash.

On October 26, 2015, EXCO closed the Fairfax Term Loan and Exchange Term Loan with an aggregate principal amount of $591 million. The proceeds were utilized to reduce $300 million of indebtedness under the Credit Agreement, $376 million in principal on the 2018 Notes and $201 million in principal on the 2022 Notes. The fees and other expenses associated with the issuance of the Fairfax Term Loan and the Exchange Term Loan are estimated to be $15 million. EXCO's net debt would have been $270 million lower on a pro forma basis if these transactions had occurred on September 30, 2015. In connection with the issuance with the senior secured second lien term loans, EXCO amended its Credit Agreement which established a borrowing base of $375 million. EXCO's liquidity would have been $395 million on a pro forma basis if these transactions had occurred on September 30, 2015. These transactions triggered a modification of certain covenants in the Credit Agreement, including a reduction in the interest coverage to at least 1.25x and the elimination of the leverage ratio.

Risk Management Results

Table 6: Hedging position as of September 30, 2015

3Q 15; mixed measures



		Three Months Ended		Twelve Months Ended		Twelve Months Ended		Twelve Months Ended
		12/31/15		12/31/16		12/31/17		12/31/18
Factors	Unit	Volume	Strike Price	Volume	Strike Price	Volume	Strike Price	Volume	Strike Price
Natural gas
Fixed price swaps - Henry Hub	Bbtu/$/Mmbtu	12,650	4.02	23,790	3.23	10,950	3.28	3,650	3.15
Three-way collars - Henry Hub	Bbtu	6,900		10,980		—		—
Sold call options	$/Mmbtu		4.47		4.80		—		—
Purchased put options	$/Mmbtu		3.83		3.90		—		—
Sold put options	$/Mmbtu		3.33		3.40		—		—
Sold call options - Henry Hub	Bbtu/$/Mmbtu	5,060	4.29	—	—	—	—	—	—

Oil
Fixed price swaps - WTI	Mbbl/$/Bbl	253	84.18	915	61.89	—	—	—	—
Fixed price swaps - LLS	Mbbl/$/Bbl	69	94.75	—	—	—	—	—	—
Fixed price basis swaps	Mbbl/$/Bbl	23	6.10	—	—	—	—	—	—
Sold call options - WTI	Mbbl/$/Bbl	92	100.00	—	—	—	—	—	—

As of September 30, 2015, approximately 69% of the 2015 forecasted natural gas production and 53% of the 2015 forecasted oil production has been hedged. During the third quarter 2015, EXCO entered into 2016 swap contracts covering 183 Mbbl of oil at a price of $50.15 and 7,320 Bbtu of natural gas at a price of $3.09, 2017 swap contracts

covering 3,650 Bbtu of natural gas at a price of $3.00, and 2018 swap contracts covering 3,650 Bbtu of natural gas at a price of $3.15.

Financial Data

The following financial statements are attached.



Attachment	Statements	Company	Period
1	Condensed Consolidated Balance Sheets	EXCO Resources, Inc.	9/30/2015
2	Condensed Consolidated Statements Of Operations	EXCO Resources, Inc.	9/30/2015
3	Condensed Consolidated Statements Of Cash Flows	EXCO Resources, Inc.	9/30/2015
4	EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations	EXCO Resources, Inc.	9/30/2015
5	GAAP Net Income (Loss) and Adjusted Net Income (Loss) Reconciliations	EXCO Resources, Inc.	9/30/2015

EXCO will host a conference call on Wednesday, October 28, 2015 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#24918640. 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 November 28, 2015. Please call (800) 585-8367 and enter conference ID#24918640 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 Vice President 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.

###

This press release contains statements that are forward-looking statements as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, among others, statements regarding estimates, expectations and production forecasts for 2015, estimates of costs and expenses for 2015, and EXCO’s drilling program. It is important to communicate expectations of future performance to investors. However, events may occur in the future that EXCO is unable to accurately predict, or over which EXCO has no control. Users of the financial statements are cautioned not to place undue reliance on a forward-looking statement. Any number of factors could cause actual results to differ materially from those in EXCO's forward-looking statements, including, but not limited to, the volatility of oil and natural gas prices, future capital requirements and the availability of capital and financing, uncertainties about reserve estimates, the outcome of future drilling activity, environmental risks and regulatory changes. Declines in oil or natural gas prices may have a material adverse effect on EXCO's financial condition, liquidity, results of operations, ability to fund operations and the amount of oil or natural gas that can be produced economically. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. EXCO undertakes no obligation to publicly update or revise any forward-looking statements. When considering EXCO's forward-looking statements, investors are urged to read the cautionary statements and the risk factors included in EXCO's Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission ("SEC") on February 25, 2015, as amended by Amendment No. 1 to Annual Report on Form 10-K/A filed with the SEC on April 10, 2015 and its other periodic filings with the SEC.



(in thousands)	September 30, 2015			December 31, 2014
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	20,511		$	46,305
Restricted cash	21,454			23,970
Accounts receivable, net:
Oil and natural gas	60,732			81,720
Joint interest	22,986			65,398
Other	17,159			8,945
Derivative financial instruments	55,000			97,278
Inventory and other	7,640			7,150
Total current assets	205,482			330,766
Equity investments	55,036			55,985
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	119,046			276,025
Proved developed and undeveloped oil and natural gas properties	3,234,377			3,852,073
Accumulated depletion	(2,588,970		)	(2,414,461		)
Oil and natural gas properties, net	764,453			1,713,637
Other property and equipment, net	27,802			24,644
Deferred financing costs, net	24,670			30,636
Derivative financial instruments	9,007			2,138
Deferred income taxes	18,749			35,935
Goodwill	163,155			163,155
Total assets	$	1,268,354		$	2,356,896
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	100,309		$	110,211
Revenues and royalties payable	129,101			152,651
Drilling advances	12,825			37,648
Accrued interest payable	22,504			26,265
Current portion of asset retirement obligations	1,769			1,769
Income taxes payable	—			—
Deferred income taxes	18,749			35,935
Derivative financial instruments	3			892
Total current liabilities	285,260			365,371
Long-term debt	1,545,106			1,446,535
Derivative financial instruments	30			—
Asset retirement obligations and other long-term liabilities	38,434			34,986
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,655,812 shares issued and 283,061,149 shares outstanding at September 30, 2015; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014	276			270
Additional paid-in capital	3,518,523			3,502,209
Accumulated deficit	(4,111,643		)	(2,984,860		)
Treasury shares, at cost; 594,663 shares at September 30, 2015 and 578,042 at December 31, 2014	(7,632		)	(7,615		)
Total shareholders’ equity	(600,476		)	510,004
Total liabilities and shareholders’ equity	$	1,268,354		$	2,356,896



	Three Months Ended									Nine Months Ended
(in thousands, except per share data)	September 30, 2015			June 30, 2015			September 30, 2014			September 30, 2015			September 30, 2014
Revenues:
Total revenues	$	83,526		$	93,742		$	151,042		$	263,588		$	532,480
Costs and expenses:
Oil and natural gas operating costs	12,669			14,135			14,099			41,745			48,713
Production and ad valorem taxes	5,944			5,603			7,978			16,408			22,951
Gathering and transportation	23,743			24,785			25,822			74,243			76,473
Depletion, depreciation and amortization	52,013			61,658			64,913			176,160			201,441
Impairment of oil and natural gas properties	339,393			394,327			—			1,010,047			—
Accretion of discount on asset retirement obligations	574			568			709			1,698			2,085
General and administrative	13,393			12,597			14,059			41,227			50,901
Other operating items	(228		)	1,534			663			1,118			6,382
Total costs and expenses	447,501			515,207			128,243			1,362,646			408,946
Operating income (loss)	(363,975		)	(421,465		)	22,799			(1,099,058		)	123,534
Other income (expense):
Interest expense, net	(27,761		)	(25,571		)	(23,974		)	(80,822		)	(70,106		)
Gain (loss) on derivative financial instruments	37,348			(6,631		)	42,844			54,427			(14,896		)
Other income	21			47			53			119			176
Equity income (loss)	(152		)	(535		)	(153		)	(1,452		)	548
Total other income (expense)	9,456			(32,690		)	18,770			(27,728		)	(84,278		)
Income (loss) before income taxes	(354,519		)	(454,155		)	41,569			(1,126,786		)	39,256
Income tax expense	—			—			—			—			—
Net income (loss)	$	(354,519	)	$	(454,155	)	$	41,569		$	(1,126,786	)	$	39,256
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(1.30	)	$	(1.67	)	$	0.15		$	(4.14	)	$	0.15
Weighted average common shares outstanding	273,348			271,549			270,631			272,147			267,316
Diluted:
Net income (loss)	$	(1.30	)	$	(1.67	)	$	0.15		$	(4.14	)	$	0.15
Weighted average common shares and common share equivalents outstanding	273,348			271,549			272,066			272,147			267,690



	Nine Months Ended September 30,
(in thousands)	2015			2014
Operating Activities:
Net income (loss)	$	(1,126,786	)	$	39,256
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	176,160			201,441
Equity-based compensation expense	4,045			4,370
Accretion of discount on asset retirement obligations	1,698			2,085
Impairment of oil and natural gas properties	1,010,047			—
(Income) loss from equity method investments	1,452			(548		)
(Gain) loss on derivative financial instruments	(54,427		)	14,896
Cash receipts (payments) of derivative financial instruments	88,977			(32,187		)
Amortization of deferred financing costs and discount on debt issuance	11,083			9,891
Other non-operating items	(13		)	(8		)
Effect of changes in:
Restricted cash with related party	(1,500		)	—
Accounts receivable	59,238			60,201
Other current assets	1,062			(1,135		)
Accounts payable and other current liabilities	(44,180		)	60,103
Net cash provided by operating activities	126,856			358,365
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(269,708		)	(297,736		)
Property acquisitions	(7,608		)	(12,987		)
Proceeds from disposition of property and equipment	7,397			76,536
Restricted cash	4,016			(1,389		)
Net changes in advances to joint ventures	8,594			(3,181		)
Equity investments and other	1,455			1,749
Net cash used in investing activities	(255,854		)	(237,008		)
Financing Activities:
Borrowings under credit agreements	97,500			40,000
Repayments under credit agreements	—			(884,970		)
Proceeds received from issuance of 2022 Notes	—			500,000
Proceeds from issuance of common shares, net	9,829			271,760
Payments of common share dividends	(62		)	(40,604		)
Deferred financing costs and other	(4,063		)	(10,076		)
Net cash provided by (used in) financing activities	103,204			(123,890		)
Net decrease in cash	(25,794		)	(2,533		)
Cash at beginning of period	46,305			50,483
Cash at end of period	$	20,511		$	47,950
Supplemental Cash Flow Information:
Cash interest payments	$	81,913		$	69,257
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	$	2,861		$	4,432
Capitalized interest	10,121			15,410
Issuance of common shares for director services	150			185



	Three Months Ended									Nine Months Ended
(in thousands)	September 30, 2015			June 30, 2015			September 30, 2014			September 30, 2015			September 30, 2014
Net income (loss)	$	(354,519	)	$	(454,155	)	$	41,569		$	(1,126,786	)	$	39,256
Interest expense	27,761			25,571			23,974			80,822			70,106
Income tax expense	—			—			—			—			—
Depletion, depreciation and amortization	52,013			61,658			64,913			176,160			201,441
EBITDA(1)	$	(274,745	)	$	(366,926	)	$	130,456		$	(869,804	)	$	310,803
Accretion of discount on asset retirement obligations	574			568			709			1,698			2,085
Impairment of oil and natural gas properties	339,393			394,327			—			1,010,047			—
Other items impacting comparability	641			2,897			1,747			6,709			11,122
Equity (income) loss	152			535			153			1,452			(548		)
(Gain) loss on derivative financial instruments	(37,348		)	6,631			(42,844		)	(54,427		)	14,896
Cash receipts (payments) on derivative financial instruments	31,938			29,401			2,282			88,977			(32,187		)
Equity-based compensation expense	926			1,439			1,118			4,045			4,370
Adjusted EBITDA (1)	$	61,531		$	68,872		$	93,621		$	188,697		$	310,541
Interest expense	(27,761		)	(25,571		)	(23,974		)	(80,822		)	(70,106		)
Income tax expense	—			—			—			—			—
Amortization of deferred financing costs and discount	4,108			2,099			2,194			11,083			9,891
Other operating items impacting comparability and non-operating items	(654		)	(2,897		)	(1,755		)	(6,722		)	(11,130		)
Changes in working capital	(18,572		)	9,171			20,157			14,620			119,169
Net cash provided by operating activities	$	18,652		$	51,674		$	90,243		$	126,856		$	358,365



	Three Months Ended								Nine Months Ended
(in thousands)	September 30, 2015		June 30, 2015			September 30, 2014			September 30, 2015			September 30, 2014
Cash flow from operations, GAAP	$	18,652	$	51,674		$	90,243		$	126,856		$	358,365
Net change in working capital	18,572		(9,171		)	(20,157		)	(14,620		)	(119,169		)
Other operating items impacting comparability	641		2,897			1,747			6,709			11,122
Adjusted operating cash flow, non-GAAP measure (2)	$	37,865	$	45,400		$	71,833		$	118,945		$	250,318



	Three Months Ended									Nine Months Ended
(in thousands)	September 30, 2015			June 30, 2015			September 30, 2014			September 30, 2015			September 30, 2014
Cash flow from operations, GAAP	$	18,652		$	51,674		$	90,243		$	126,856		$	358,365
Less: Additions to oil and natural gas properties, gathering assets and equipment	(65,108		)	(83,712		)	(100,395		)	(269,708		)	(297,736		)
Free cash flow, non-GAAP measure (3)	$	(46,456	)	$	(32,038	)	$	(10,152	)	$	(142,852	)	$	60,629

(1)

Earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”) represents net income (loss) 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, equity-based compensation and income or losses from equity method investments. EXCO has 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, similar measures are used in covenant calculations required under the Credit Agreement, the indenture governing the 2018 Notes, the indenture governing the 2022 Notes and the term loan credit agreements governing the Second Lien Term Loans. Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to the Company. EXCO's 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 the Company's 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 the Company’s operating, investing and financing activities. As such, investors are encouraged 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 Credit Agreement, the indenture governing the 2018 Notes, the indenture governing the 2022 Notes and the term loan credit agreements governing the Second Lien Term Loans.

(2)

Adjusted operating cash flow is presented because the Company believes it is a useful financial indicator for companies in its 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. Adjusted 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. Other operating items impacting comparability have been excluded as they do not reflect the Company's on-going operating activities.


(3)	Free cash flow is cash provided by operating activities less capital expenditures. This non-GAAP measure is used predominantly as a forecasting tool to estimate cash available to fund indebtedness and other investments.



	Three Months Ended																		Nine Months Ended
	September 30, 2015						June 30, 2015						September 30, 2014						September 30, 2015						September 30, 2014
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share			Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	(354,519	)				$	(454,155	)				$	41,569					$	(1,126,786	)				$	39,256
Adjustments:
(Gain) loss on derivative financial instruments	(37,348		)				6,631						(42,844		)				(54,427		)				14,896
Cash receipts (payments) on derivative financial instruments	31,938						29,401						2,282						88,977						(32,187		)
Impairment of oil and natural gas properties	339,393						394,327						—						1,010,047						—
Adjustments included in equity (income) loss	195						334						—						1,031						(1,749		)
Other items impacting comparability	641						2,897						1,747						6,709						11,122
Deferred finance cost amortization acceleration	2,007						—						—						4,771						3,471
Income taxes on above adjustments (1)	(134,730		)				(173,436		)				15,526						(422,843		)				1,779
Adjustment to deferred tax asset valuation allowance (2)	141,808						181,662						(16,628		)				450,714						(15,702		)
Total adjustments, net of taxes	343,904						441,816						(39,917		)				1,084,979						(18,370		)
Adjusted net income (loss) (5)	$	(10,615	)				$	(12,339	)				$	1,652					$	(41,807	)				$	20,886

Net income (loss), GAAP (3)	$	(354,519	)	$	(1.30	)	$	(454,155	)	$	(1.67	)	$	41,569		$	0.15		$	(1,126,786	)	$	(4.14	)	$	39,256		$	0.15
Adjustments shown above (3)	343,904			1.26			441,816			1.62			(39,917		)	(0.14		)	1,084,979			3.99			(18,370		)	(0.07		)
Dilution attributable to equity-based payments (4)	—			—			—			—			—			—			—			—			—			—
Adjusted net income (loss) (5)	$	(10,615	)	$	(0.04	)	$	(12,339	)	$	(0.05	)	$	1,652		$	0.01		$	(41,807	)	$	(0.15	)	$	20,886		$	0.08

Common share and equivalents used for earnings (loss) per share (EPS):
Weighted average common shares outstanding	273,348						271,549						270,631						272,147						267,316
Dilutive stock options	—						—						—						—						—
Dilutive restricted shares and restricted share units	—						—						1,435						—						374
Dilutive warrants	—						—						—						—						—
Shares used to compute diluted EPS for adjusted net income (loss)	273,348						271,549						272,066						272,147						267,690


(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 warrants, dilutive restricted shares and diluted restricted share units calculated in accordance with the treasury stock method.


(5)	Adjusted net income (loss), a non-GAAP measure, includes adjustments for gains or losses from asset sales, unrealized gains or losses from derivative financial instruments, non-cash impairments and other items typically not included by securities analysts in published estimates.

Attachment

Statements

Condensed Consolidated Balance Sheets

EXCO Resources, Inc.