EXCO RESOURCES INC - FORM 8-K - EX-99.1 - Q1 2016 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

EXCO RESOURCES, INC. REPORTS FIRST QUARTER

2016 RESULTS

DALLAS, TEXAS, May 3, 2016…EXCO Resources, Inc. (NYSE: XCO) (“EXCO” or the "Company") today announced operating and financial results for the first quarter 2016.

2016 First Quarter Highlights


•	Drilled 5 gross (4.6 net) and turned-to-sales 8 gross (3.6 net) operated horizontal wells in the first quarter 2016. Reduced costs by approximately 20% for wells turned-to-sales in 2016 compared to 2015.


•	Produced 295 Mmcfe per day, or 27 Bcfe, for the first quarter 2016, in line with the mid-point of guidance. Production decreased 24 Mmcfe per day, or 8%, from the fourth quarter 2015, primarily due to normal production declines and timing of wells turned-to-sales.


•	Adjusted EBITDA, a non-GAAP measure, was $19 million for the first quarter 2016, 62% below adjusted EBITDA for the fourth quarter 2015, primarily due to lower cash receipts on derivative contracts, commodity prices and production. This was partially offset by decreases in lease operating expenses and general and administrative costs.


•	Adjusted net loss, a non-GAAP measure, was $20 million, or $0.07 per diluted share, and GAAP net loss was $130 million, or $0.47 per diluted share, for the first quarter 2016. The GAAP net loss was primarily due to the $135 million impairment of oil and natural gas properties pursuant to the ceiling test in accordance with full cost accounting.


•	Cost saving initiatives resulted in lease operating expenses below the low-end of guidance and general and administrative costs at the low-end of guidance. These initiatives resulted in 25% lower lease operating expenses and 27% lower general and administrative expenses (excluding equity-based compensation and severance costs) from the fourth quarter 2015.


•	Liquidity was $256 million at March 31, 2016. EXCO continued to execute transactions to enhance its capital structure, including additional repurchases of $54 million of senior unsecured notes with $8 million in cash during the quarter.


•	Capital budget for 2016 was reduced to $85 million to preserve liquidity and capital resources, representing a reduction of $192 million, or 69%, compared to 2015.

Key Developments

Strategic plan update

EXCO's strategic plan continues to focus on the following three core objectives: 1) restructuring the balance sheet to enhance its capital structure and extend structural liquidity, 2) transforming EXCO into the lowest cost producer, and 3) optimizing and repositioning its portfolio. The three core objectives and the Company's recent progress are detailed below:

Restructuring the balance sheet to enhance its capital structure and extend structural liquidity - The Company is focused on improving its capital structure and providing structural liquidity. During the first quarter 2016, the lenders under EXCO’s credit agreement ("Credit Agreement") completed their regular semi-annual redetermination, which resulted in a borrowing base of $325 million, a 13% decline from the previous $375 million borrowing base. Over the same period, forward 12-month natural gas strip prices declined by approximately 23%. As of March 31, 2016, EXCO had $256 million in liquidity. During the first quarter 2016, EXCO completed additional transactions focused on reducing its indebtedness including the repurchase of $14 million and $40 million in principal amount of senior unsecured notes due 2018 ("2018 Notes") and senior unsecured notes due 2022 ("2022 Notes"), respectively, with $8 million in cash. These repurchases resulted in an estimated reduction in interest expense of approximately $4 million per year. Since the third quarter 2015, EXCO has reduced the aggregate principal amount of outstanding senior unsecured notes by $924 million, or 74%. The Company continues to evaluate additional initiatives to accomplish this objective, including the repurchase, refinancing or restructuring of existing indebtedness, and the issuance of additional indebtedness or equity.

Transforming EXCO into the lowest cost producer - EXCO continues to exercise fiscal discipline to transform itself into the lowest cost producer. The Company has implemented several initiatives to reduce its lease operating costs and general and administrative expenses, including significant reductions in its workforce. For the first quarter 2016, lease operating expenses decreased by 25% and general and administrative expenses (excluding equity-based compensation and severance costs) decreased by 27% from the fourth quarter 2015. The reductions in lease operating expenses included the renegotiation of saltwater disposal contracts, modifications to chemical programs and less workover activity. In April 2016, EXCO modified the schedule for certain employees in the Appalachia region that reduced work hours by 20% compared to the first quarter 2016. Since the fourth quarter 2015, the Company has reduced its general and administrative employees by approximately 20%. The Company expects its lease operating expenses and general and administrative expenses to continue to decrease in 2016 as it realizes a full year of cost savings from the reductions in force and other initiatives.

Optimizing and repositioning the portfolio - The Company continues to execute its disciplined capital allocation program to ensure the highest and best uses of capital. EXCO has reduced its total 2016 capital budget to $85 million, a reduction of $192 million, or 69%, as compared to 2015 capital expenditures of $277 million. While the Company's portfolio contains a significant number of economic development opportunities in the current commodity price environment, it has deferred development to preserve its liquidity and capital resources. In addition, the Company is evaluating the divestiture of certain non-core assets to generate capital that can be redeployed to projects with higher rates of return.

Operational Results

Table 1: Summary of operating activities and operational results

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q1	Fiscal
		3/31/16	12/31/15			3/31/15			3/31/16	3/31/15			2016	2016
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Rig counts (1)	#	2	3	(33	)	4	(50	)	2	4	(50	)	2	1

Net wells drilled (1)
North Louisiana	#	4.6	—	100		1.7	171		4.6	1.7	171		N/A	N/A
East Texas	#	—	2.7	(100	)	2.0	(100	)	—	2.0	(100	)	N/A	N/A
South Texas	#	—	—	—		1.8	(100	)	—	1.8	(100	)	N/A	N/A
Appalachia and other	#	—	—	—		—	—		—	—	—		N/A	N/A
Total net wells drilled	#	4.6	2.7	70		5.5	(16	)	4.6	5.5	(16	)	4.3	5.8

Net wells turned-to-sales (1)
North Louisiana	#	—	—	—		10.5	(100	)	—	10.5	(100	)	N/A	N/A
East Texas	#	3.6	2.0	80		—	100		3.6	—	100		N/A	N/A
South Texas	#	—	1.8	(100	)	4.1	(100	)	—	4.1	(100	)	N/A	N/A
Appalachia and other	#	—	0.5	(100	)	—	—		—	—	—		N/A	N/A
Total net wells turned-to-sales	#	3.6	4.3	(16	)	14.6	(75	)	3.6	14.6	(75	)	3.6	9.4

Daily production
North Louisiana	Mmcfe/d	151	174	(13	)	207	(27	)	151	207	(27	)	N/A	N/A
East Texas	Mmcfe/d	63	64	(2	)	45	40		63	45	40		N/A	N/A
South Texas	Mmcfe/d	39	44	(11	)	36	8		39	36	8		N/A	N/A
Appalachia and other	Mmcfe/d	42	37	14		51	(18	)	42	51	(18	)	N/A	N/A
Total daily production	Mmcfe/d	295	319	(8	)	339	(13	)	295	339	(13	)	290-300	290-310

Production
Oil	Mbbls	550	609	(10	)	504	9		550	504	9		525-535	1,840-1,860
Natural gas	Bcf	23.5	25.7	(9	)	27.5	(15	)	23.5	27.5	(15	)	23.2-24.1	95.1-102.3
Total production	Bcfe	26.8	29.3	(9	)	30.5	(12	)	26.8	30.5	(12	)	26.4-27.3	106.1-113.5

Capital Expenditures	$MM	37	35	6		103	(64	)	37	103	(64	)	N/A	85


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

North Louisiana

Highlights:


•	Produced 151 Mmcfe per day, a decrease of 23 Mmcfe per day, or 13%, from the fourth quarter 2015 and a decrease of 56 Mmcfe per day, or 27%, from the first quarter 2015.


•	Drilled 5 gross (4.6 net) operated Haynesville shale wells during the first quarter 2016.

EXCO’s decrease in production compared to the fourth quarter 2015 was primarily the result of normal production declines. EXCO operated an average of two drilling rigs to drill 5 gross (4.6 net) Haynesville shale wells in the first quarter 2016, which are planned to be turned-to-sales in the second and third quarters 2016. The Company also plans to drill and complete an additional 1 gross (0.9 net) well in 2016. The first three wells drilled in 2016 featured completion methods that included the use of approximately 2,700 lbs of proppant per lateral foot and average lateral lengths of approximately 4,300 feet. The average drilling time for these wells was 25 days, including a well drilled in 23 days, which is the best drilling performance in the Company's history of drilling over 400 wells in the North Louisiana region. The cost of these wells is expected to be approximately $6.0 million. The remaining three wells in the 2016 capital budget will also feature enhanced completion methods, such as increased amounts of proppant and cross-unit laterals of approximately 7,500 feet. These wells are expected to have an average cost of $8.0 million per well. The Company is targeting rates of return^(*) in excess of 35% in this region during 2016. The additional volumes from these wells turned-to-sales are expected to increase production in this region in the second and third quarters 2016.

The Company has implemented several initiatives to enhance and manage its base production in the region including a full field compression program in the Holly area that began in late 2015 and has already demonstrated sustained performance improvements.

East Texas

Highlights:


•	Produced 63 Mmcfe per day, consistent with the fourth quarter 2015 and an increase of 18 Mmcfe per day, or 40%, from the first quarter 2015.


•	Turned-to-sales 8 gross (3.6 net) wells in the Haynesville and Bossier shales.

EXCO’s production was consistent with the fourth quarter 2015 primarily due to natural production declines offset by additional wells that were turned-to-sales late in the first quarter 2016. The wells turned-to-sales included 5 gross (2.2 net) wells in the Haynesville shale and 3 gross (1.4 net) wells in the Bossier shale. These wells utilized 2,100 to 2,800 lbs of proppant per lateral foot and have yielded strong results. The average cost for the Haynesville and Bossier shale wells turned-to-sales during the first quarter 2016 was approximately $9.4 million. The average drilling and completion costs for these wells represent a decrease of approximately 20% compared to wells drilled by EXCO in this region during 2015.

EXCO recently completed its second Haynesville shale well since 2012 in Nacogdoches County, Texas. The well has performed above expectations with an initial production rate of 13.2 Mmcfe per day on a 17/64th restricted choke with a flowing tubing pressure of 9,469 psi. The continued strong results of both wells show further upside of the predominantly undeveloped southern area of the Company's East Texas position that includes over 100 undeveloped prospective gross locations. The Company plans to drill and complete an additional 1 gross (0.3 net) well in this area during 2016.

South Texas

Highlights:


•	Produced 6.5 Mboe per day, a decrease of 0.8 Mboe per day, or 11%, from the fourth quarter 2015 and an increase of 0.5 Mboe per day, or 8%, from the first quarter 2015.

EXCO’s decrease in production compared to the fourth quarter 2015 was primarily due to normal production declines as EXCO suspended drilling in this area in the second half of 2015. The Company's acreage in the South Texas region is approximately 81% held-by-production, including 100% of its core area, which allows EXCO flexibility in the timing of development in this region.

Appalachia

Highlights:


•	Produced 42 Mmcfe per day, an increase of 5 Mmcfe per day, or 14%, from the fourth quarter 2015 and a decrease of 9 Mmcfe per day, or 18%, from the first quarter 2015.

EXCO’s increase in production compared to the fourth quarter 2015 was primarily attributable to lower shut-in production from its Marcellus shale wells due to improved regional market prices for natural gas. Shut-in production due to low regional market prices was approximately 8 Mmcfe per day during the first quarter 2016 compared to 11 Mmcfe per day during the fourth quarter 2015. The Company's position in the Marcellus shale requires low maintenance capital and is approximately 84% held-by-production allowing the opportunity for future development activities with minimal costs to hold the position.

EXCO continues to focus on reducing its operating costs in the Appalachia region, which has resulted in a decrease in lease operating expenses of 43% compared to the fourth quarter 2015. In April 2016, EXCO modified the schedule for certain employees that reduced work hours by 20% compared to the first quarter 2016.

(*)

Rates of return are based on NYMEX futures prices as of March 31, 2016, including natural gas prices per Mmbtu of $2.19 for 2016, $2.77 for 2017, $2.87 for 2018, $2.93 for 2019, $3.03 for 2020, $3.17 for 2021, $3.34 for 2022, $3.49 for 2023, $3.65 for 2024 and $3.80 thereafter, and oil prices per Bbl of $39.62 for 2016, $44.91 for 2017, $47.03 for 2018, $48.68 for 2019, $49.97 for 2020, $50.93 for 2021, $51.55 for 2022 and $52.11 thereafter.



Financial Results

Table 2: Summary of operational earnings

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Q1	Fiscal
		3/31/16		12/31/15				3/31/15				3/31/16		3/31/15				2016	2016
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Guidance	Guidance
Operating revenues
Oil revenues	$MM	16		23		(30	)	21		(24	)	16		21		(24	)	N/A	N/A
Natural gas revenues	$MM	36		42		(14	)	65		(45	)	36		65		(45	)	N/A	N/A
Total revenues	$MM	52		65		(20	)	86		(40	)	52		86		(40	)	N/A	N/A
Realized oil prices	$/Bbl	28.15		37.63		(25	)	41.43		(32	)	28.15		41.43		(32	)	N/A	N/A
Oil price differentials	$/Bbl	(5.23	)	(4.57	)	14		(6.96	)	(25	)	(5.23	)	(6.96	)	(25	)	(4.00-6.00)	(4.00-6.00)
Realized gas prices	$/Mcf	1.54		1.63		(6	)	2.38		(35	)	1.54		2.38		(35	)	N/A	N/A
Gas price differentials	$/Mcf	(0.55	)	(0.65	)	(15	)	(0.60	)	(8	)	(0.55	)	(0.60	)	(8	)	(0.60-0.70)	(0.60-0.70)

Derivative financial instruments
Cash settlements (payments)	$MM	17		40		(58	)	28		(39	)	17		28		(39	)	N/A	N/A
Cash settlements (payments)	$/Mcfe	0.63		1.36		(54	)	0.91		(31	)	0.63		0.91		(31	)	N/A	N/A

Costs and expenses
Oil and natural gas operating costs	$MM	9		12		(25	)	15		(40	)	9		15		(40	)	N/A	N/A
Production and ad valorem taxes	$MM	5		6		(17	)	5		—		5		5		—		N/A	N/A
Gathering and transportation	$MM	27		25		8		26		4		27		26		4		N/A	N/A
Oil and natural gas operating costs	$/Mcfe	0.35		0.41		(15	)	0.49		(29	)	0.35		0.49		(29	)	0.40-0.45	0.35-0.40
Production and ad valorem taxes	$/Mcfe	0.17		0.21		(19	)	0.16		6		0.17		0.16		6		0.15-0.20	0.15-0.20
Gathering and transportation	$/Mcfe	0.99		0.86		15		0.84		18		0.99		0.84		18		0.90-0.95	0.95-1.00
General and administrative (1)	$MM	7		14		(50	)	14		(50	)	7		14		(50	)	7-8	25-27

Operational earnings
Adjusted EBITDA (2)	$MM	19		50		(62	)	58		(67	)	19		58		(67	)	N/A	N/A
GAAP net loss (3)	$MM	(130	)	(66	)	97		(318	)	(59	)	(130	)	(318	)	(59	)	N/A	N/A
Adjusted net loss (2)	$MM	(20	)	(9	)	122		(19	)	5		(20	)	(19	)	5		N/A	N/A
GAAP diluted shares outstanding	MM	278		278		—		272		2		278		272		2		N/A	N/A
Adjusted diluted shares outstanding	MM	278		278		—		272		2		278		272		2		N/A	N/A
GAAP diluted EPS	$/Share	(0.47	)	(0.24	)	96		(1.17	)	(60	)	(0.47	)	(1.17	)	(60	)	N/A	N/A
Adjusted diluted EPS	$/Share	(0.07	)	(0.03	)	133		(0.07	)	—		(0.07	)	(0.07	)	—		N/A	N/A


(1)	Excludes equity-based compensation expenses of $3.8 million, $3.2 million and $1.7 million for the three months ended March 31, 2016, December 31, 2015 and March 31, 2015, respectively.


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


(3)	GAAP net loss included impairments of oil and natural gas properties of $135 million, $205 million and $276 million for the three months ended March 31, 2016, December 31, 2015 and March 31, 2015, respectively.

EXCO’s decrease in adjusted EBITDA compared to the fourth quarter 2015 was primarily due to lower cash receipts on derivative contracts and lower revenues as a result of lower realized oil and natural gas prices and lower production. These decreases were partially offset by the implementation of cost reduction initiatives that reduced general and administrative expenses and oil and natural gas operating costs. Gathering and transportation expense increased due to taking natural gas in-kind from certain third-party operated wells in the North Louisiana region, which also resulted in improved natural gas price differentials. The benefit of taking natural gas in-kind attributed to natural gas price differentials below the low-end of guidance. The GAAP net loss in each of the quarters presented in the table above 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.

Cash Flow Results

Table 3: Summary of key cash flow items

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Q1	Fiscal
		3/31/16		12/31/15				3/31/15				3/31/16		3/31/15				2016	2016
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Guidance	Guidance
Cash flow provided by (used in)
Operating activities	$MM	28		7		300		57		(51	)	28		57		(51	)	N/A	N/A
Investing activities	$MM	(37	)	(45	)	(18	)	(120	)	(69	)	(37	)	(120	)	(69	)	N/A	N/A
Financing activities	$MM	43		30		43		43		—		43		43		—		N/A	N/A
Net increase (decrease) in cash	$MM	34		(8	)	(525	)	(21	)	(262	)	34		(21	)	(262	)	N/A	N/A

Other key cash flow items
Adjusted operating cash flow (1)	$MM	3		30		(90	)	36		(92	)	3		36		(92	)	N/A	N/A
Free cash flow (1)	$MM	(5	)	(41	)	(88	)	(64	)	(92	)	(5	)	(64	)	(92	)	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 increase in operating cash flows compared to the fourth quarter 2015 was primarily the result of favorable working capital conversions in the first quarter 2016, partially offset by lower revenues and lower cash receipts on derivative contracts. During the first quarter 2016, EXCO primarily used its cash flows from operations and borrowings under its Credit Agreement to fund its development. The Company's cash used in investing activities is expected to decline during the remainder of the year in connection with its reduced development program. EXCO's financing activities in the first quarter 2016 included repurchases of the 2018 Notes and 2022 Notes and payments on the $400 million second lien term loan ("Exchange Term Loan").

Liquidity Results

Table 4: Financial flexibility measures

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q1	Fiscal
		3/31/16	12/31/15			3/31/15			3/31/16	3/31/15			2016	2016
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Cash (1)	$MM	74	33	124		48	54		74	48	54		N/A	N/A
Gross debt (2)	$MM	1,159	1,148	1		1,497	(23	)	1,159	1,497	(23	)	N/A	N/A
Net debt	$MM	1,086	1,115	(3	)	1,450	(25	)	1,086	1,450	(25	)	N/A	N/A
Adjusted EBITDA (3)	$MM	19	50	(62	)	58	(67	)	19	58	(67	)	N/A	N/A
Cash interest expenses (4)	$MM	17	21	(19	)	26	(35	)	17	26	(35	)	17-19	65-70
Adjusted EBITDA/Interest (5)	x	1.12	2.38	(53	)	2.23	(50	)	1.12	2.23	(50	)	N/A	N/A
Sr. Secured debt/LTM Adj. EBITDA (5)	x	0.67	0.28	139		0.73	(8	)	0.67	0.73	(8	)	N/A	N/A
Net debt/LTM Adjusted EBITDA	x	5.46	4.68	17		4.30	27		5.46	4.30	27		N/A	N/A


(1)	Includes restricted cash of $28 million, $21 million and $22 million as of March 31, 2016, December 31, 2015 and March 31, 2015, respectively.


(2)	Represents total principal balance outstanding. See Table 5 below for reconciliation to carrying value.


(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. In addition, cash payments under the Exchange Term Loan are not considered interest expense per FASB ASC 470-60, Troubled Debt Restructuring by Debtors ("ASC 470-60") and are excluded from the cash interest expenses amounts shown. EXCO's expected payments on the Exchange Term Loan in 2016 are $50 million. See Table 5 below for additional information on the accounting treatment of the Exchange Term Loan.

(5)

These ratios differ in certain respects from the calculations of comparable measures in the Credit Agreement. As of March 31, 2016, the ratio of consolidated EBITDAX to consolidated interest expense (as defined in the agreement) was 2.2 to 1.0 and the ratio of senior secured indebtedness (excluding the senior secured second lien term loans) to consolidated EBITDAX (as defined in the agreement) was 0.7 to 1.0.

Table 5: Reconciliation of carrying value to principal

1Q 16; $MM



		3/31/16 (Actual)
Factors	Unit	Carrying value		Deferred reduction in carrying value (1)		Unamortized discount/deferred financing costs	Principal balance
Credit Agreement	$MM	133		—		—	133
Exchange Term Loan (1)	$MM	629		(229	)	—	400
Fairfax Term Loan	$MM	300		—		—	300
2018 Notes	$MM	143		—		1	144
2022 Notes	$MM	183		—		—	183
Deferred financing costs, net	$MM	(17	)	—		17	—
Total Debt	$MM	1,370		(229	)	18	1,159

(1)

The issuance of the Exchange Term Loan and related repurchases of 2018 Notes and 2022 Notes were accounted for in accordance with ASC 470-60. As a result, the carrying amount of the Exchange Term Loan is equal to the total undiscounted future cash payments, including interest and principal. All cash payments under the terms of the Exchange Term Loan, whether designated as interest or as principal amount, will reduce the carrying amount and no interest expense will be recognized. The undiscounted future interest payments on the Exchange Term Loan expected to be due in the next twelve months are classified as Current portion of long-term debt on the balance sheet. As such, the Company's reported interest expense will be less than the contractual payments throughout the term of the Exchange Term Loan.

Table 6: Liquidity schedule

Historical vs. guidance; $MM



		Quarter-to-Date							Year-to-Date				Q1	Fiscal
		3/31/16	12/31/15			3/31/15			3/31/16	3/31/15			2016	2016
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Borrowing base on revolver	$MM	325	375	(13	)	725	(55	)	325	725	(55	)	N/A	N/A
Amount drawn on revolver	$MM	133	67	99		247	(46	)	133	247	(46	)	N/A	N/A
Letters of credit	$MM	10	7	43		7	43		10	7	43		N/A	N/A
Available for borrowing	$MM	182	301	(40	)	471	(61	)	182	471	(61	)	N/A	N/A
Cash (1)	$MM	74	33	124		47	57		74	47	57		N/A	N/A
Liquidity (2)	$MM	256	334	(23	)	518	(51	)	256	518	(51	)	N/A	N/A


(1)	Includes restricted cash of $28 million, $21 million and $22 million as of March 31, 2016, December 31, 2015 and March 31, 2015, respectively.


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

On March 29, 2016, lenders under the Credit Agreement completed their regular semi-annual redetermination resulting in a reduction in EXCO's borrowing base from $375 million to $325 million primarily due to depressed oil and natural gas prices. There were no additional modifications to the Credit Agreement in connection with the redetermination process. The next scheduled redetermination is set to occur on or about September 1, 2016.

Risk Management Results

Table 7: Hedging position

1Q 16; mixed measures



		Nine Months Ended		Twelve Months Ended		Twelve Months Ended
		12/31/16		12/31/17		12/31/18
Factors	Unit	Volume	Strike Price	Volume	Strike Price	Volume	Strike Price
Natural gas
Fixed price swaps - Henry Hub	Bbtu/$/Mmbtu	42,625	2.88	12,750	3.15	3,650	3.15
Fixed price swaptions - Henry Hub	Bbtu/$/Mmbtu	—	—	7,300	2.76	—	—

Oil
Fixed price swaps - WTI	Mbbl/$/Bbl	825	58.61	—	—	—	—

As of March 31, 2016, approximately 57% of the remaining 2016 forecasted natural gas production and 63% of the remaining 2016 forecasted oil production has been hedged. Since March 31, 2016, EXCO entered into additional fixed price swaps covering 7,300 Bbtu of natural gas at an average price of $2.74 per Mmbtu for 2017.

Financial Data

The following financial statements are attached.



Attachment	Statements	Company	Period
1	Condensed Consolidated Balance Sheets	EXCO Resources, Inc.	3/31/2016
2	Condensed Consolidated Statements Of Operations	EXCO Resources, Inc.	3/31/2016
3	Condensed Consolidated Statements Of Cash Flows	EXCO Resources, Inc.	3/31/2016
4	EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations	EXCO Resources, Inc.	3/31/2016
5	GAAP Net Loss and Adjusted Net Loss Reconciliations	EXCO Resources, Inc.	3/31/2016

EXCO will host a conference call on Wednesday, May 4, 2016 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#24918642. 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 11, 2016. Please call (800) 585-8367 and enter conference ID#24918642 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 2016, estimates of costs and expenses for 2016, 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, 2015, filed with the Securities and Exchange Commission ("SEC") on March 2, 2016 and its other periodic filings with the SEC.



(in thousands)	March 31, 2016			December 31, 2015
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	46,216		$	12,247
Restricted cash	27,605			21,220
Accounts receivable, net:
Oil and natural gas	6,819			37,236
Joint interest	17,064			22,095
Other	5,019			8,894
Derivative financial instruments	43,370			39,499
Inventory and other	8,310			8,610
Total current assets	154,403			149,801
Equity investments	32,887			40,797
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	107,098			115,377
Proved developed and undeveloped oil and natural gas properties	2,980,231			3,070,430
Accumulated depletion	(2,656,369		)	(2,627,763		)
Oil and natural gas properties, net	430,960			558,044
Other property and equipment, net	27,852			27,812
Deferred financing costs, net	6,587			8,408
Derivative financial instruments	5,346			6,109
Goodwill	163,155			163,155
Total assets	$	821,190		$	954,126
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	73,335		$	88,049
Revenues and royalties payable	109,752			106,163
Accrued interest payable	7,811			7,846
Current portion of asset retirement obligations	845			845
Income taxes payable	—			—
Derivative financial instruments	3,322			16
Current maturities of long-term debt	50,000			50,000
Total current liabilities	245,065			252,919
Long-term debt	1,320,102			1,320,279
Asset retirement obligations and other long-term liabilities	44,029			43,251
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,971,207 shares issued and 283,376,544 shares outstanding at March 31, 2016; 283,633,996 shares issued and 283,039,333 shares outstanding at December 31, 2015	276			276
Additional paid-in capital	3,526,611			3,522,153
Accumulated deficit	(4,307,261		)	(4,177,120		)
Treasury shares, at cost; 594,663 shares at March 31, 2016 and December 31, 2015	(7,632		)	(7,632		)
Total shareholders’ equity	(788,006		)	(662,323		)
Total liabilities and shareholders’ equity	$	821,190		$	954,126



	Three Months Ended
(in thousands, except per share data)	March 31, 2016			December 31, 2015			March 31, 2015
Revenues:
Total revenues	$	51,649		$	64,743		$	86,320
Costs and expenses:
Oil and natural gas operating costs	9,478			12,158			14,941
Production and ad valorem taxes	4,640			6,222			4,861
Gathering and transportation	26,630			25,078			25,715
Depletion, depreciation and amortization	29,001			39,266			62,489
Impairment of oil and natural gas properties	134,599			205,323			276,327
Accretion of discount on asset retirement obligations	912			579			556
General and administrative	10,897			17,591			15,237
Other operating items	190			(657		)	(188		)
Total costs and expenses	216,347			305,560			399,938
Operating loss	(164,698		)	(240,817		)	(313,618		)
Other income (expense):
Interest expense, net	(19,257		)	(25,260		)	(27,490		)
Gain on derivative financial instruments	16,591			21,442			23,710
Gain on extinguishment of debt	45,114			193,276			—
Other income	12			3			51
Equity loss	(7,910		)	(14,239		)	(765		)
Total other income (expense)	34,550			175,222			(4,494		)
Loss before income taxes	(130,148		)	(65,595		)	(318,112		)
Income tax expense	—			—			—
Net loss	$	(130,148	)	$	(65,595	)	$	(318,112	)
Loss per common share:
Basic:
Net loss	$	(0.47	)	$	(0.24	)	$	(1.17	)
Weighted average common shares outstanding	278,357			277,995			271,522
Diluted:
Net loss	$	(0.47	)	$	(0.24	)	$	(1.17	)
Weighted average common shares and common share equivalents outstanding	278,357			277,995			271,522



	Three Months Ended March 31,
(in thousands)	2016			2015
Operating Activities:
Net loss	$	(130,148	)	$	(318,112	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization	29,001			62,489
Equity-based compensation expense	3,813			1,680
Accretion of discount on asset retirement obligations	912			556
Impairment of oil and natural gas properties	134,599			276,327
Loss from equity investments	7,910			765
Gain on derivative financial instruments	(16,591		)	(23,710		)
Cash receipts of derivative financial instruments	16,790			27,638
Amortization of deferred financing costs and discount on debt issuance	3,121			4,876
Other non-operating items	(20		)	—
Gain on extinguishment of debt	(45,114		)	—
Effect of changes in:
Restricted cash with related party	(1,201		)	—
Accounts receivable	38,295			22,443
Other current assets	(102		)	226
Accounts payable and other current liabilities	(13,284		)	1,352
Net cash provided by operating activities	27,981			56,530
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(32,486		)	(120,888		)
Property acquisitions	—			(7,608		)
Proceeds from disposition of property and equipment	—			6,711
Restricted cash	(5,184		)	2,117
Net changes in advances to joint ventures	1,001			(75		)
Equity investments and other	—			(503		)
Net cash used in investing activities	(36,669		)	(120,246		)
Financing Activities:
Borrowings under EXCO Resources Credit Agreement	297,897			45,000
Repayments under EXCO Resources Credit Agreement	(232,397		)	—
Payment on Exchange Term Loan	(12,639		)	—
Repurchases of senior unsecured notes	(7,863		)	—
Deferred financing costs and other	(2,341		)	(1,942		)
Net cash provided by financing activities	42,657			43,058
Net increase (decrease) in cash	33,969			(20,658		)
Cash at beginning of period	12,247			46,305
Cash at end of period	$	46,216		$	25,647
Supplemental Cash Flow Information:
Cash interest payments	$	15,583		$	29,220
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	$	260		$	969
Capitalized interest	1,339			3,734



	Three Months Ended
(in thousands)	March 31, 2016			December 31, 2015			March 31, 2015
Net loss	$	(130,148	)	$	(65,595	)	$	(318,112	)
Interest expense	19,257			25,260			27,490
Income tax expense	—			—			—
Depletion, depreciation and amortization	29,001			39,266			62,489
EBITDA (1)	$	(81,890	)	$	(1,069	)	$	(228,133	)
Accretion of discount on asset retirement obligations	912			579			556
Impairment of oil and natural gas properties	134,599			205,323			276,327
Other items impacting comparability	(1,087		)	2,463			3,172
Gain on restructuring and extinguishment of debt	(45,114		)	(193,276		)	—
Equity loss	7,910			14,239			765
Gain on derivative financial instruments	(16,591		)	(21,442		)	(23,710		)
Cash receipts of derivative financial instruments	16,790			39,823			27,638
Equity-based compensation expense	3,813			3,153			1,680
Adjusted EBITDA (1)	$	19,342		$	49,793		$	58,295
Interest expense	(19,257		)	(25,260		)	(27,490		)
Income tax expense	—			—			—
Amortization of deferred financing costs and discount	3,121			5,911			4,876
Other operating items impacting comparability and non-operating items	1,067			(2,482		)	(3,172		)
Changes in working capital	23,708			(20,791		)	24,021
Net cash provided by operating activities	$	27,981		$	7,171		$	56,530



	Three Months Ended
(in thousands)	March 31, 2016			December 31, 2015		March 31, 2015
Cash flow from operations, GAAP	$	27,981		$	7,171	$	56,530
Net change in working capital	(23,708		)	20,791		(24,021		)
Other operating items impacting comparability	(1,087		)	2,463		3,172
Adjusted operating cash flow, non-GAAP measure (2)	$	3,186		$	30,425	$	35,681



	Three Months Ended
(in thousands)	March 31, 2016			December 31, 2015			March 31, 2015
Cash flow from operations, GAAP	$	27,981		$	7,171		$	56,530
Less: Additions to oil and natural gas properties, gathering assets and equipment	(32,486		)	(47,882		)	(120,888		)
Free cash flow, non-GAAP measure (3)	$	(4,505	)	$	(40,711	)	$	(64,358	)

(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 12.5% senior secured second lien term loans due on October 26, 2020 ("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
	March 31, 2016						December 31, 2015						March 31, 2015
(in thousands, except per share amounts)	Amount			Per share			Amount			Per share			Amount			Per share
Net loss, GAAP	$	(130,148	)				$	(65,595	)				$	(318,112	)
Adjustments:
Gain on derivative financial instruments	(16,591		)				(21,442		)				(23,710		)
Gain on restructuring and extinguishment of debt	(45,114		)				(193,276		)				—
Cash receipts of derivative financial instruments	16,790						39,823						27,638
Impairment of oil and natural gas properties	134,599						205,323						276,327
Adjustments included in equity loss	7,866						14,018						502
Other items impacting comparability	(1,087		)				2,463						3,172
Deferred finance cost amortization acceleration	1,013						3,972						2,764
Income taxes on above adjustments (1)	(38,990		)				(20,352		)				(114,677		)
Adjustment to deferred tax asset valuation allowance (2)	52,059						26,238						127,245
Total adjustments, net of taxes	110,545						56,767						299,261
Adjusted net loss (5)	$	(19,603	)				$	(8,828	)				$	(18,851	)

Net loss, GAAP (3)	$	(130,148	)	$	(0.47	)	$	(65,595	)	$	(0.24	)	$	(318,112	)	$	(1.17	)
Adjustments shown above (3)	110,545			0.40			56,767			0.21			299,261			1.10
Dilution attributable to equity-based payments (4)	—			—			—			—			—			—
Adjusted net loss (5)	$	(19,603	)	$	(0.07	)	$	(8,828	)	$	(0.03	)	$	(18,851	)	$	(0.07	)

Common shares and equivalents used for loss per share:
Weighted average common shares outstanding	278,357						277,995						271,522
Dilutive stock options	—						—						—
Dilutive restricted shares and restricted share units	—						—						—
Dilutive warrants	—						—						—
Shares used to compute diluted loss per share for adjusted net loss	278,357						277,995						271,522


(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 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.