EXCO RESOURCES INC - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - 8-K - EXCO RESOURCES INC	q12015earningsreleaseform8.htm

Exhibit 99.1

EXCO Resources, Inc.

12377 Merit Drive, Suite 1700, Dallas, Texas 75251

Media Contact: (214) 368-2084

FAX (972) 367-3559

EXCO RESOURCES, INC. REPORTS FIRST QUARTER

2015 RESULTS

DALLAS, TEXAS, April 28, 2015…EXCO Resources, Inc. (NYSE: XCO) (“EXCO” or the "Company") today announced operating and financial results for the first quarter 2015.

2015 First Quarter Highlights


•	Drilled 13 gross (5.5 net) and turned-to-sales 29 gross (14.6 net) operated horizontal wells in the first quarter 2015, consistent with the capital budget.


•	Produced 339 Mmcfe per day, or 30 Bcfe, for the first quarter 2015, consistent with the midpoint of guidance. Production increased 7 Mmcfe per day from the fourth quarter 2014 excluding the impact of an asset divestiture.


•	Adjusted EBITDA was $58 million for the first quarter 2015, 28% below adjusted EBITDA for the fourth quarter 2014 primarily due to lower oil and natural gas prices and partially offset by lower operating costs.


•	Drilled and completed first operated Buda well with results above expectations, including a maximum 24-hour rate of 580 Bbls of oil.


•	Amended credit agreement to provide operational and financial flexibility.


•	Implemented cost saving initiatives, including a 15% reduction in the workforce, and negotiated cost reductions with numerous vendors. General and administrative costs were below the low-end of guidance.


•	Adjusted net income (loss), a non-GAAP measure, was a net loss of $19 million, or $0.07 per diluted share, and GAAP net income (loss) was a net loss of $318 million, or $1.17 per diluted share, for the first quarter 2015. The GAAP net loss was primarily due to the impairment of the Company’s oil and natural gas properties pursuant to the ceiling test in accordance with full cost accounting.

Key Developments

Appointment of Chief Executive Officer and Chief Operating Officer

On March 31, 2015, EXCO's Board of Directors appointed Harold L. Hickey to the position of Chief Executive Officer and President of EXCO. Mr. Hickey previously served as EXCO's President and Chief Operating Officer since February

2013 and Chief Operating Officer since October 2005. On April 17, 2015, EXCO's Board of Directors appointed Harold H. Jameson to the position of Chief Operating Officer of EXCO. Mr. Jameson most recently served as EXCO’s Vice President of Development and Production with primary responsibilities including the horizontal shale development drilling programs in the Haynesville, Eagle Ford and Marcellus assets. Mr. Jameson has served in a Vice President role at EXCO since March 2011.

Services and investment agreement

On March 31, 2015, EXCO entered into a four-year services and investment agreement with Bluescape Resources Company LLC ("Bluescape"), a Dallas-based independent energy investment and advisory company. The agreement provides that Bluescape will perform certain strategic advisory services including the development and execution of a strategic improvement plan. Pursuant to the agreement, Bluescape agreed to purchase $10 million of common shares from EXCO upon effectiveness of a resale registration statement covering such shares and $40 million of common shares through open market purchases within one year of the closing of the agreement. In exchange for the ongoing strategic advisory services, EXCO pays a monthly fee, an annual incentive payment and has issued warrants to purchase EXCO's common shares. The annual incentive payment and exercisability of the warrants are dependent on EXCO's common share price achieving certain performance hurdles as compared to a peer group. The closing of the transactions under this agreement will be subject to certain conditions, including, among others, obtaining certain approvals from EXCO’s shareholders. The warrants will automatically terminate and become void and of no force or effect if the closing does not occur. At the closing, C. John Wilder, Executive Chairman of Bluescape, will become Executive Chairman of EXCO's Board of Directors.

Operational Results

Table 1: Summary of operating activities and operational results

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Fiscal
		3/31/2015	12/31/2014			3/31/2014			3/31/2015	3/31/2014			2015
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Estimate
Rig counts	#	4	7	(43	)	10	(60	)	4	10	(60	)	4

Net wells drilled
North Louisiana	#	1.7	4.1	(59	)	4.1	(59	)	1.7	4.1	(59	)	1.7
East Texas	#	2.0	—	100		1.9	5		2.0	1.9	5		9.7
South Texas	#	1.8	4.8	(63	)	4.7	(62	)	1.8	4.7	(62	)	6.6
Appalachia and other	#	—	0.5	(100	)	—	—		—	—	—		0.3
Total net wells drilled	#	5.5	9.4	(41	)	10.7	(49	)	5.5	10.7	(49	)	18.3

Net wells turned-to-sales
North Louisiana	#	10.5	4.5	133		0.7	1,400		10.5	0.7	1,400		11.7
East Texas	#	—	1.9	(100	)	—	—		—	—	—		6.5
South Texas	#	4.1	5.2	(21	)	2.4	71		4.1	2.4	71		11.2
Appalachia and other	#	—	—	—		—	—		—	—	—		0.5
Total net wells turned-to-sales	#	14.6	11.6	26		3.1	371		14.6	3.1	371		29.9

Daily production
North Louisiana	Mmcfe/d	207	193	7		259	(20	)	207	259	(20	)	N/A
East Texas	Mmcfe/d	45	47	(4	)	22	105		45	22	105		N/A
South Texas	Mmcfe/d	36	37	(3	)	39	(8	)	36	39	(8	)	N/A
Appalachia and other (1)	Mmcfe/d	51	63	(19	)	87	(41	)	51	87	(41	)	N/A
Total daily production	Mmcfe/d	339	340	—		407	(17	)	339	407	(17	)	N/A
Total production	Bcfe	30	31	(3	)	37	(19	)	30	37	(19	)	N/A

Capital expenditures	$MM	103	122	(16	)	100	3		103	100	3		275


(1)	Includes 8 Mmcfe/d and 24 Mmcfe/d of production from Compass Production Partners, LP ("Compass") for the three months ended December 31, 2014 and March 31, 2014, respectively. EXCO sold its interest in Compass on October 31, 2014.

North Louisiana

Highlights:


•	Produced 207 Mmcfe per day, an increase of 14 Mmcfe per day, or 7%, from the fourth quarter 2014 and a decrease of 52 Mmcfe per day, or 20%, from the first quarter 2014.


•	Drilled 2 gross (1.7 net) operated horizontal Haynesville wells in Caddo Parish and turned-to-sales 14 gross (10.5 net) wells primarily in the Holly area of DeSoto Parish.

EXCO’s increase in production compared to the fourth quarter 2014 was primarily the result of completion activities. The Company entered 2015 with three operated rigs drilling in this region and subsequently moved these rigs to the Shelby area of East Texas. Current plans in North Louisiana for the remainder of 2015 include turning 4 gross (1.2 net) wells to sales, which are currently waiting on completion.

EXCO turned-to-sales a test well in the Bossier shale in January 2015 to assess the potential productivity of the formation. This was the Company's first well drilled in the Bossier shale in North Louisiana since 2010. The well is currently flowing at a restricted rate of approximately 5.3 Mmcf per day with 6,700 psi flowing pressure. EXCO will continue to evaluate the potential for further Bossier shale development, which in North Louisiana could result in more than 300 additional gross drilling locations based on a standard lateral length of 4,300 feet.

EXCO completed its sixth re-frac stimulation test on mature Haynesville shale wells in January 2015. The Company has seen significant increases in production from the treated wells, including in the first stimulation test performed in

July 2014. The first treated well was producing 0.5 Mmcf per day prior to the treatment and the initial production rate after the treatment was 1.8 Mmcf per day on a 10/64th choke. After nine months, the well is currently producing 1.3 Mmcf per day with 2,000 psi flowing pressure. The re-frac resulted in an incremental 2 Bcf of proved reserves for the well for the year ended 2014. The success to date in the re-frac program supports the potential for additional re-frac stimulation opportunities in both partially and fully developed units. EXCO has identified more than 270 gross wells that are re-frac candidates in North Louisiana and East Texas. The estimated cost to perform a re-frac is approximately $1.8 million and could vary based on the design and type of treatment.

East Texas

Highlights:


•	Produced 45 Mmcfe per day, a decrease of 2 Mmcfe per day, or 4%, from the fourth quarter 2014 and an increase of 23 Mmcfe per day, or 105%, from the first quarter 2014.


•	Drilled 4 gross (2.0 net) operated horizontal Haynesville and Bossier wells in the Shelby area.

EXCO’s decrease in production compared to the fourth quarter 2014 was primarily the result of normal production declines in the Shelby area since the most recent well turned-to-sales during October 2014. The East Texas region is the primary focus of EXCO’s 2015 development program, and EXCO plans to drill an additional 17 gross (7.7 net) operated horizontal wells and turn 14 gross (6.5 net) wells to sales in 2015.

EXCO has continued to realize cost reductions from key vendors, with the average cost per well expected to be $10.8 million for the 2015 program as compared to $12.8 million for a well with approximately the same lateral length as of the first quarter 2014. The design for the wells in the 2015 program includes more proppant per foot and average lateral lengths in excess of 7,000 feet.

EXCO remains encouraged by the results of the 2014 drilling program, and the undeveloped locations in this area are anticipated to provide attractive rates of return in the current commodity price environment. The strong performance from the wells included in the Company’s 2014 drilling program resulted in proved reserves in this area of 1.3 Bcf per 1,000 lateral feet for proved undeveloped locations and 1.75 Bcf per 1,000 lateral feet for certain proved developed producing wells. The Company has approximately 250 undeveloped gross locations in this region based on 880 foot spacing between wells.

South Texas

Highlights:


•	Produced 6.0 Mboe per day, a decrease of 0.2 Mboe per day, or 3%, from the fourth quarter 2014 and a decrease of 0.5 Mboe per day, or 8%, from the first quarter 2014.


•	Drilled 7 gross (1.8 net) operated horizontal wells and turned-to-sales 15 gross (4.1 net) operated horizontal wells.

EXCO’s decrease in production compared to the fourth quarter 2014 was primarily the result of higher downtime for construction and maintenance of central production and storage facilities and offset frac activities. Development was focused on the Eagle Ford shale and included 1 gross (0.7 net) Buda well which was drilled and turned-to-sales. The Company is currently in the process of evaluating its drilling plans in the Eagle Ford shale for the remainder of 2015. EXCO anticipates drilling and turning-to-sales 3 gross (2.0 net) wells in the Buda formation. Due to improvements in drilling performance and cost reduction efforts, the Company reduced its average cost per well in the Eagle Ford to between $6.0 million and $6.9 million depending on lateral length as compared to $7.1 million as of the first quarter 2014. Drilling days per well in the Eagle Ford are currently averaging 10 days from spud to rig release, and EXCO recently drilled a well in 8.8 days. The third central production facility in the Company's core area became operational in the first quarter 2015, and approximately 40% of gross operated production in the region flows through central production facilities. A third-party is currently in the process of constructing a pipeline from these central production facilities to an intrastate pipeline in Dilley, Texas. This connection is expected to be operational by the third quarter 2015.

EXCO remains excited by the potential of the Buda formation in its South Texas leasehold. EXCO’s average cost per well in the Buda is expected to be approximately $3.0 million during 2015; the Company's first Buda well had a 9,800 foot lateral and was turned-to-sales in early February 2015. The well’s maximum 24-hour production rate was 580

Bbls of oil, exceeding pre-drill expectations, and the well was still producing above 435 Bbls of oil per day at the end of the first quarter 2015. Cumulative to date, the well has produced more than 30,000 Bbls of oil. EXCO participated in two non-operated Buda wells during the first quarter 2015 and is currently drilling an offset operated well. The relatively low costs of drilling the Buda provide an attractive near-term development opportunity, even in a low commodity price environment. Based on the success of Buda wells drilled to date, EXCO revised its 2015 development plans to include additional operated wells.

EXCO closed the first acquisition of wells drilled under its participation agreement with a joint venture partner in March 2015, which included interests in 3 gross (1.4 net) wells. The total purchase price for this acquisition was $7.6 million, and given the net production from the acquired interests averaged 260 Bbls of oil per day during the month preceding the effective date, EXCO effectively paid under $30,000 per flowing barrel of oil for the proved developed production. EXCO made a second offer in April 2015 which included a total of 10 gross (5.2 net) wells for a total offer price of $14.0 million. EXCO currently estimates that an additional 25 to 30 wells will be included in offers during the remainder of 2015.

Appalachia

Highlights:


•	Produced 51 Mmcfe per day, a decrease of 4 Mmcfe per day, or 7%, from the fourth quarter 2014 and a decrease of 10 Mmcfe per day, or 16%, from the first quarter 2014.


•	Completed 1 gross (0.5 net) operated horizontal Marcellus well in Northeast Pennsylvania.

EXCO’s decrease in production from the fourth quarter 2014 was primarily the result of normal production declines and downtime due to inclement weather. The horizontal Marcellus well drilled in the first quarter was located near EXCO’s most successful Marcellus well to date, and the new well exhibited a similar result based on initial flowback data. The well is currently awaiting construction of a gathering line and is expected to be turned-to-sales in the third quarter 2015. EXCO’s plans for the remainder of 2015 include drilling 1 gross (0.3 net) operated horizontal well in the Marcellus. 75% of EXCO’s acreage in the Marcellus shale is held-by-production, allowing for significant optionality in development pace.



Financial Results

Table 2: Summary of operational earnings

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Fiscal
		3/31/2015		12/31/2014				3/31/2014				3/31/2015		3/31/2014				2015
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Estimate
Operating revenues
Operating revenues	$MM	86		128		(33	)	198		(57	)	86		198		(57	)	N/A
Realized oil prices	$/Bbl	41.43		70.56		(41	)	88.25		(53	)	41.43		88.25		(53	)	N/A
Oil price differentials	$/Bbl	(6.96	)	(2.34	)	(197	)	(10.15	)	31		(6.96	)	(10.15	)	31		(4.00-6.00)
Realized gas prices	$/Mcf	2.38		3.23		(26	)	4.42		(46	)	2.38		4.42		(46	)	N/A
Gas price differentials	$/Mcf	(0.60	)	(0.82	)	27		(0.47	)	(28	)	(0.60	)	(0.47	)	(28	)	(0.50-0.60)

Derivative financial instruments
Cash settlements (payments)	$MM	28		13		115		(20	)	240		28		(20	)	240		N/A
Cash settlements (payments)	$/Mcfe	0.91		0.42		117		(0.54	)	269		0.91		(0.54	)	269		N/A

Costs and expenses
Oil and natural gas operating costs	$MM	15		16		(6	)	19		(21	)	15		19		(21	)	N/A
Production and ad valorem taxes	$MM	5		7		(29	)	8		(38	)	5		8		(38	)	N/A
Gathering and transportation	$MM	26		25		4		25		4		26		25		4		N/A
Oil and natural gas operating costs	$/Mcfe	0.49		0.50		(2	)	0.51		(4	)	0.49		0.51		(4	)	0.40-0.45
Production and ad valorem taxes	$/Mcfe	0.16		0.22		(27	)	0.21		(24	)	0.16		0.21		(24	)	0.15-0.20
Gathering and transportation	$/Mcfe	0.84		0.80		5		0.67		25		0.84		0.67		25		0.80-0.85
General and administrative (1)	$MM	14		14		—		16		(13	)	14		16		(13	)	47.5-52.5

Operational earnings
Adjusted EBITDA (2)	$MM	58		81		(28	)	112		(48	)	58		112		(48	)	N/A
GAAP net income (loss)	$MM	(318	)	81		(493	)	(5	)	N/M		(318	)	(5	)	N/M		N/A
Adjusted net income (loss) (2)	$MM	(19	)	(4	)	(375	)	12		(258	)	(19	)	12		(258	)	N/A
GAAP diluted shares outstanding	MM	272		271		—		261		4		272		261		4		N/A
Adjusted diluted shares outstanding	MM	272		271		—		261		4		272		261		4		N/A
GAAP diluted EPS	$/Share	(1.17	)	0.30		(490	)	(0.02	)	N/M		(1.17	)	(0.02	)	N/M		N/A
Adjusted diluted EPS	$/Share	(0.07	)	(0.02	)	(250	)	0.05		(240	)	(0.07	)	0.05		(240	)	N/A


(1)	Excludes share-based compensation expenses of $1.7 million, $0.6 million and $1.5 million for the three months ended March 31, 2015, December 31, 2014 and March 31, 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 fourth quarter 2014 was due primarily to lower commodity prices in the current period and partially offset by lower operating costs. The GAAP net loss during the first quarter 2015 was primarily due to the impairment of the Company’s oil and natural gas properties pursuant to the ceiling test in accordance with full cost accounting.

EXCO reduced its workforce by 15% in February 2015 and incurred $2.6 million in severance costs. Excluding the impact of the severance costs, general and administrative expenses decreased 24% from the fourth quarter 2014 (excluding share-based compensation expenses).

Cash Flow Results

Table 3: Summary of key cash flow items

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Fiscal
		3/31/2015		12/31/2014				3/31/2014				3/31/2015		3/31/2014				2015
Factors ($MM)	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Estimate
Cash flow provided by (used in)
Operating activities	$MM	57		4		1,325		200		(72	)	57		200		(72	)	N/A
Investing activities	$MM	(120	)	15		(900	)	(24	)	(400	)	(120	)	(24	)	(400	)	N/A
Financing activities	$MM	43		(21	)	305		(133	)	132		43		(133	)	132		N/A
Net increase (decrease) in cash	$MM	(21	)	(2	)	(950	)	44		(148	)	(21	)	44		(148	)	N/A

Other key cash flow items
Adjusted operating cash flow (1)	$MM	36		59		(39	)	94		(62	)	36		94		(62	)	N/A
Free cash flow (1)	$MM	(64	)	(90	)	29		99		(165	)	(64	)	99		(165	)	N/A


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

During the first quarter 2015, EXCO primarily used its cash flows from operations and borrowings under its credit agreement ("EXCO Resources Credit Agreement") to fund drilling and development.

Liquidity Results

Table 4: Financial flexibility measures

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Fiscal
		3/31/2015	12/31/2014			3/31/2014			3/31/2015	3/31/2014			2015
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Estimate
Cash (1)	$MM	48	70	(31	)	105	(54	)	48	105	(54	)	N/A
Gross debt (2)	$MM	1,497	1,452	3		1,424	5		1,497	1,424	5		N/A
Net debt	$MM	1,450	1,382	5		1,319	10		1,450	1,319	10		N/A
Liquidity (3)	$MM	518	761	(32	)	622	(17	)	518	622	(17	)	N/A
Adjusted EBITDA (4)	$MM	58	81	(28	)	112	(48	)	58	112	(48	)	N/A
Cash interest expenses (5)	$MM	26	26	—		22	18		26	22	18		N/A
Adjusted EBITDA/Interest (6)	x	2.23	3.12	(29	)	5.09	(56	)	2.23	5.09	(56	)	N/A
Secured debt/LTM Adjusted EBITDA (6)	x	0.73	0.52	40		1.55	(53	)	0.73	1.55	(53	)	N/A
Net debt/LTM Adjusted EBITDA	x	4.30	3.53	22		3.04	41		4.30	3.04	41		N/A


(1)	Includes restricted cash of $22 million, $24 million and $17 million as of March 31, 2015, December 31, 2014 and March 31, 2014, respectively.


(2)	Excludes unamortized discount of $6 million, $6 million and $10 million as of March 31, 2015, December 31, 2014 and March 31, 2014, respectively.


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


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


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


(6)	These ratios differ in certain respects from the calculations of comparable measures in the EXCO Resources Credit Agreement. As of March 31, 2015, the ratio of consolidated EBITDAX to consolidated interest expense (as defined in the agreement) was 3.0 to 1.0 and the ratio of secured indebtedness to consolidated EBITDAX (as defined in the agreement) was 0.8 to 1.0.

On February 6, 2015, EXCO amended the EXCO Resources Credit Agreement, which resulted in a borrowing base redetermination of $725 million. The next borrowing base redetermination under the EXCO Resources Credit Agreement will occur in August 2015. Additionally, the financial covenants were amended to include an interest coverage ratio and senior secured indebtedness to consolidated EBITDA ratio. The leverage ratio was suspended until

the fourth quarter 2016, and the ratio requirements thereafter were modified. The amendments to the financial covenants provide EXCO the financial flexibility to selectively develop its asset base.

Risk Management Results

Table 5: Hedging position as of March 31, 2015

1Q 15; mixed measures



		Nine Months Ended		Twelve Months Ended		Twelve Months Ended
		12/31/2015		12/31/2016		12/31/2017
Factors	Unit	Volume	Strike Price	Volume	Strike Price	Volume	Strike Price
Natural gas
Fixed price swaps - Henry Hub	Bbtu/$/Mmbtu	37,813	4.02	9,150	3.37	7,300	3.42
Three-way collars - Henry Hub	Bbtu	20,625		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	15,125	4.29	—	—	—	—

Oil
Fixed price swaps - WTI	Mbbl/$/Bbl	757	84.18	183	63.15	—	—
Fixed price swaps - LLS	Mbbl/$/Bbl	206	94.75	—	—	—	—
Fixed price basis swaps	Mbbl/$/Bbl	69	6.10	—	—	—	—
Sold call options - WTI	Mbbl/$/Bbl	275	100.00	—	—	—	—

As of March 31, 2015, approximately 68% of the 2015 forecasted natural gas production and 55% of the 2015 forecasted oil production has been hedged.

Financial Data

The following financial statements are attached.



Attachment	Statements	Company	Period
1	Condensed Consolidated Balance Sheets	EXCO Resources, Inc.	3/31/2015
2	Condensed Consolidated Statements Of Operations	EXCO Resources, Inc.	3/31/2015
3	Condensed Consolidated Statements Of Cash Flows	EXCO Resources, Inc.	3/31/2015
4	EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations	EXCO Resources, Inc.	3/31/2015
5	GAAP Net Income and Adjusted Net Income Reconciliations	EXCO Resources, Inc.	3/31/2015

EXCO will host a conference call on Wednesday, April 29, 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#24918638. The conference call will also be webcast on EXCO’s website at www.excoresources.com under the Investor Relations tab. Presentation materials related to this release will be posted on EXCO’s website prior to the conference call. A digital recording will be available starting two hours after the completion of the conference call until May 13, 2015. Please call (800) 585-8367 and enter conference ID#24918638 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, EXCO’s drilling program, and the closing of the transactions under the services and investment agreement. 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)	March 31, 2015			December 31, 2014
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	25,647		$	46,305
Restricted cash	21,853			23,970
Accounts receivable, net:
Oil and natural gas	55,038			81,720
Joint interest	67,822			65,398
Other	10,322			8,945
Derivative financial instruments	89,091			97,278
Inventory and other	8,611			7,150
Total current assets	278,384			330,766
Equity investments	55,723			55,985
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	257,961			276,025
Proved developed and undeveloped oil and natural gas properties	3,697,417			3,852,073
Accumulated depletion	(2,476,361		)	(2,414,461		)
Oil and natural gas properties, net	1,479,017			1,713,637
Other property and equipment, net	24,252			24,644
Deferred financing costs, net	28,038			30,636
Derivative financial instruments	5,743			2,138
Deferred income taxes	31,882			35,935
Goodwill	163,155			163,155
Total assets	$	2,066,194		$	2,356,896
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	127,749		$	110,211
Revenues and royalties payable	124,935			152,651
Drilling advances	34,634			37,648
Accrued interest payable	22,705			26,265
Current portion of asset retirement obligations	1,769			1,769
Income taxes payable	—			—
Deferred income taxes	31,882			35,935
Derivative financial instruments	239			892
Total current liabilities	343,913			365,371
Long-term debt	1,491,886			1,446,535
Asset retirement obligations	35,959			34,986
Commitments and contingencies	—			—
Shareholders’ equity:
Common shares, $0.001 par value; 350,000,000 authorized shares; 274,280,158 shares issued and 273,702,116 shares outstanding at March 31, 2015; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014	270			270
Additional paid-in capital	3,504,752			3,502,209
Accumulated deficit	(3,302,971		)	(2,984,860		)
Treasury shares, at cost; 578,042 shares at March 31, 2015 and December 31, 2014	(7,615		)	(7,615		)
Total shareholders’ equity	194,436			510,004
Total liabilities and shareholders’ equity	$	2,066,194		$	2,356,896



	Three Months Ended
(in thousands, except per share data)	March 31, 2015			December 31, 2014			March 31, 2014
Revenues:
Total revenues	$	86,320		$	127,789		$	198,472
Costs and expenses:
Oil and natural gas operating costs	14,941			15,754			18,787
Production and ad valorem taxes	4,861			6,908			7,609
Gathering and transportation	25,715			25,101			24,613
Depletion, depreciation and amortization	62,489			62,128			69,275
Impairment of oil and natural gas properties	276,327			—			—
Accretion of discount on asset retirement obligations	556			605			681
General and administrative	15,237			15,019			17,338
Other operating items	(188		)	(1,067		)	2,746
Total costs and expenses	399,938			124,448			141,049
Operating income (loss)	(313,618		)	3,341			57,423
Other income (expense):
Interest expense, net	(27,490		)	(24,178		)	(20,164		)
Gain (loss) on derivative financial instruments	23,710			102,561			(43,022		)
Other income	51			65			46
Equity income (loss)	(765		)	(376		)	1,111
Total other income (expense)	(4,494		)	78,072			(62,029		)
Income (loss) before income taxes	(318,112		)	81,413			(4,606		)
Income tax expense	—			—			—
Net income (loss)	$	(318,112	)	$	81,413		$	(4,606	)
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(1.17	)	$	0.30		$	(0.02	)
Weighted average common shares outstanding	271,522			271,053			260,716
Diluted:
Net income (loss)	$	(1.17	)	$	0.30		$	(0.02	)
Weighted average common shares and common share equivalents outstanding	271,522			271,053			260,716



	Three Months Ended March 31,
(in thousands)	2015			2014
Operating Activities:
Net loss	$	(318,112	)	$	(4,606	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	62,489			69,275
Share-based compensation expense	1,680			1,507
Accretion of discount on asset retirement obligations	556			681
Impairment of oil and natural gas properties	276,327			—
(Income) loss from equity method investments	765			(1,111		)
(Gain) loss on derivative financial instruments	(23,710		)	43,022
Cash settlements (payments) of derivative financial instruments	27,638			(19,810		)
Amortization of deferred financing costs and discount on debt issuance	4,876			2,444
Effect of changes in:
Accounts receivable	22,443			14,576
Other current assets	226			(2,517		)
Accounts payable and other current liabilities	1,352			96,873
Net cash provided by operating activities	56,530			200,334
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(120,888		)	(101,404		)
Property acquisitions	(7,608		)	(426		)
Proceeds from disposition of property and equipment	6,711			76,259
Restricted cash	2,117			3,627
Net changes in advances to joint ventures	(75		)	(3,549		)
Equity method investments	(503		)	1,749
Net cash used in investing activities	(120,246		)	(23,744		)
Financing Activities:
Borrowings under credit agreements	45,000			—
Repayments under credit agreements	—			(391,174		)
Proceeds from issuance of common shares, net	—			272,139
Payments of common share dividends	(15		)	(13,521		)
Deferred financing costs and other	(1,927		)	(5		)
Net cash provided by (used in) financing activities	43,058			(132,561		)
Net increase (decrease) in cash	(20,658		)	44,029
Cash at beginning of period	46,305			50,483
Cash at end of period	$	25,647		$	94,512
Supplemental Cash Flow Information:
Cash interest payments	$	29,220		$	37,113
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	$	969		$	1,485
Capitalized interest	3,734			4,790
Issuance of common stock for director services	50			69



	Three Months Ended
(in thousands)	March 31, 2015			December 31, 2014			March 31, 2014
Net income (loss)	$	(318,112	)	$	81,413		$	(4,606	)
Interest expense	27,490			24,178			20,164
Income tax expense	—			—			—
Depletion, depreciation and amortization	62,489			62,128			69,275
EBITDA(1)	$	(228,133	)	$	167,719		$	84,833
Accretion of discount on asset retirement obligations	556			605			681
Impairment of oil and natural gas properties	276,327			—			—
Other items impacting comparability	3,172			714			2,600
Equity (income) loss	765			376			(1,111		)
(Gain) loss on derivative financial instruments	(23,710		)	(102,561		)	43,022
Cash settlements (payments) on derivative financial instruments	27,638			13,196			(19,810		)
Share based compensation expense	1,680			592			1,507
Adjusted EBITDA (1)	$	58,295		$	80,641		$	111,722
Interest expense	(27,490		)	(24,178		)	(20,164		)
Income tax expense	—			—			—
Amortization of deferred financing costs and discount	4,876			2,164			2,444
Other operating items impacting comparability	(3,172		)	(723		)	(2,600		)
Changes in working capital	24,021			(54,176		)	108,932
Net cash provided by operating activities	$	56,530		$	3,728		$	200,334



	Three Months Ended
(in thousands)	March 31, 2015			December 31, 2014		March 31, 2014
Cash flow from operations, GAAP	$	56,530		$	3,728	$	200,334
Net change in working capital	(24,021		)	54,176		(108,932		)
Other operating items impacting comparability	3,172			714		2,600
Adjusted operating cash flow, non-GAAP measure (2)	$	35,681		$	58,618	$	94,002



	Three Months Ended
(in thousands)	March 31, 2015			December 31, 2014			March 31, 2014
Cash flow from operations, GAAP	$	56,530		$	3,728		$	200,334
Less: Additions to oil and natural gas properties, gathering assets and equipment	(120,888		)	(94,040		)	(101,404		)
Free cash flow, non-GAAP measure (3)	$	(64,358	)	$	(90,312	)	$	98,930

(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, share-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 EXCO Resources Credit Agreement, the indenture governing EXCO's 7.5% senior notes due September 15, 2018 ("2018 Notes"), and the indenture governing EXCO's 8.5% senior notes due April 15, 2022 ("2022 Notes"). 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 EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the indenture governing the 2022 Notes.

(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
	March 31, 2015						December 31, 2014						March 31, 2014
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share
Net income (loss), GAAP	$	(318,112	)				$	81,413					$	(4,606	)
Adjustments:
(Gain) loss on derivative financial instruments	(23,710		)				(102,561		)				43,022
Cash settlements (payments) on derivative financial instruments	27,638						13,196						(19,810		)
Impairment of oil and natural gas properties	276,327						—						—
Adjustments included in equity (income) loss	502						296						(1,749		)
Other items impacting comparability	3,172						714						2,600
Deferred finance cost amortization acceleration	2,764						—						372
Income taxes on above adjustments (1)	(114,677		)				35,342						(9,774		)
Adjustment to deferred tax asset valuation allowance (2)	127,245						(32,565		)				1,842
Total adjustments, net of taxes	299,261						(85,578		)				16,503
Adjusted net income (loss) (5)	$	(18,851	)				$	(4,165	)				$	11,897

Net income (loss), GAAP (3)	$	(318,112	)	$	(1.17	)	$	81,413		$	0.30		$	(4,606	)	$	(0.02	)
Adjustments shown above (3)	299,261			1.10			(85,578		)	(0.32		)	16,503			0.07
Dilution attributable to share-based payments (4)	—			—			—			—			—			—
Adjusted net income (loss) (5)	$	(18,851	)	$	(0.07	)	$	(4,165	)	$	(0.02	)	$	11,897		$	0.05

Common share and equivalents used for earnings (loss) per share (EPS):
Weighted average common shares outstanding	271,522						271,053						260,716
Dilutive stock options	—						—						—
Dilutive restricted shares and restricted share units	—						—						257
Shares used to compute diluted EPS for adjusted net income (loss)	271,522						271,053						260,973


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


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


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


(4)	Represents dilution per share attributable to common share equivalents from in-the-money stock options, dilutive restricted shares and 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.