EXCO RESOURCES INC - FORM 8-K - EX-99.1 - Q4 2015 EARNINGS RELEASE

Attached files

Attached files

Stock widget

Investing forum

EXCO RESOURCES INC Reports

file	filename
8-K - FORM 8-K - EXCO RESOURCES INC	q42015earningsreleaseform8.htm

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 FOURTH QUARTER AND FULL YEAR

2015 RESULTS

DALLAS, TEXAS, March 1, 2016…EXCO Resources, Inc. (NYSE: XCO) (“EXCO” or the "Company") today announced fourth quarter and full year operating and financial results for 2015.



2015 Fourth Quarter and Full Year Highlights

•

Liquidity was $334 million at December 31, 2015. EXCO executed a series of transactions during the fourth quarter 2015 that reduced its aggregate principal amount of debt outstanding by $402 million from the third quarter 2015 as part of its ongoing balance sheet restructuring program. The Company repurchased $49 million of senior unsecured notes for $7 million in cash subsequent to the fourth quarter 2015. EXCO's plans for 2016 are focused on capital preservation and protecting its liquidity.


•	EXCO delivered operational and financial results within guidance for the full year 2015 with the exception of capital expenditures, which were lower than guidance due to reductions in spending in response to the decline in commodity prices.


•	Proved reserves were 907.3 Bcfe and PV-10 calculated using the prices prescribed by the Securities and Exchange Commission ("SEC PV-10") was $402 million, as of December 31, 2015. PV-10 of proved reserves based on NYMEX futures prices as of December 31, 2015 ("NYMEX PV-10") was $811 million^(*).

•

Produced 319 Mmcfe per day, or 29.3 Bcfe, for the fourth quarter 2015 and produced 340 Mmcfe per day, or 124.0 Bcfe, for the full year 2015, in line with the mid-point of guidance. Production decreased 21 Mmcfe per day, or 6%, from the third quarter 2015, primarily due to lower production in the Appalachia region as EXCO pro-actively shut-in wells due to low regional natural gas prices and normal production declines. Production decreased 10 Mmcfe per day, or 3%, from full year 2014 excluding divested assets, primarily due to normal production declines and a reduced development program.


•	Adjusted EBITDA, a non-GAAP measure, was $50 million for the fourth quarter 2015, 19% below adjusted EBITDA for the third quarter 2015, and $238 million for the full year 2015, 39% below adjusted EBITDA for the full year 2014, primarily due to lower commodity prices and production.


•	Adjusted net loss, a non-GAAP measure, was $9 million, or $0.03 per diluted share, and GAAP net loss was $66 million, or $0.24 per diluted share, for the fourth quarter 2015. Adjusted net loss was $51 million, or $0.19 per diluted share, and GAAP net loss was $1.2 billion, or $4.36 per diluted share, for the full year 2015. The GAAP net loss 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 of $205 million and $1.2 billion for the fourth quarter and full year 2015, respectively.


•	Drilled 6 gross (2.7 net) and turned-to-sales 8 gross (4.3 net) operated horizontal wells in the fourth quarter 2015 and drilled 37 gross (17.8 net) and turned to sales 68 gross (29.2 net) operated horizontal wells for the full year 2015.

Key Developments

Strategic plan update

EXCO recently refined its strategic plan to focus on the following three core objectives: 1) restructuring the balance sheet to enhance business and extend structural liquidity, 2) transforming EXCO into the lowest cost producer, and 3) optimizing and repositioning the portfolio. The Company believes the execution of this strategy will allow it to persevere through the current commodity price cycle and create long-term value for its shareholders. The three core objectives and the Company's recent progress are detailed below:

Restructuring the balance sheet to enhance business and extend structural liquidity - The Company is focused on improving its capital structure and providing structural liquidity. EXCO executed a series of transactions during fourth quarter 2015 to enhance its liquidity and financial flexibility, including the execution of a 12.5% senior secured second lien term loan in the aggregate principal amount of $300 million (“Fairfax Term Loan”) and a 12.5% senior secured second lien term loan in the aggregate principal amount of $400 million (“Exchange Term Loan”). The proceeds from the Fairfax Term Loan were used to reduce approximately $300 million of outstanding indebtedness under EXCO’s credit agreement (“Credit Agreement”). EXCO used the proceeds from the Exchange Term Loan to repurchase an aggregate of $551 million principal amount of its 7.5% senior unsecured notes due September 15, 2018 ("2018 Notes") and an aggregate of $277 million principal amount of its 8.5% senior unsecured notes due April 15, 2022 (“2022 Notes”). The second lien term loans are due in October 2020 and accrue interest at a rate of 12.5% per annum. Additionally, EXCO repurchased $41 million in principal amount of the 2018 Notes with $12 million in cash in the fourth quarter of 2015 and $9 million in principal amount of the 2018 Notes and $40 million in principal amount of the 2022 Notes with $7 million in cash in February 2016, resulting in an estimated reduction in interest expense of approximately $6 million per year. EXCO is currently evaluating additional balance sheet restructuring transactions including the issuance of additional indebtedness, the restructuring or repurchase of existing indebtedness, issuance of equity or divestitures of assets. EXCO's liquidity was $334 million as of year-end 2015 and the Company has approximately $125 million of liens capacity that can be utilized for future exchanges or issuances of secured indebtedness.

EXCO believes that fourth quarter 2015 open market purchases of common shares by funds associated with EXCO directors demonstrates their commitment to the Company. In the fourth quarter 2015, Fairfax Financial Holdings Limited (“Fairfax”) purchased an aggregate of 8.0 million common shares in the open market, resulting in a 9.0% ownership stake as reported in SEC filings, and Energy Strategic Advisory LLC (“ESAS”) purchased an aggregate of 12.5 million common shares in the open market pursuant to its agreement entered into earlier in 2015, increasing its ownership to 6.5%, as reported in SEC filings. As of year-end 2015, common shares held by EXCO’s directors, officers and their respective affiliates, associates and related funds in the aggregate constituted approximately 51% of the outstanding common shares.

In addition, EXCO continued to reduce its costs under commercial contracts and renegotiated a natural gas sales contract in North Louisiana during the first quarter 2016 that improved the rate per Mcfe in exchange for extending the term of the contract. This is expected to result in annual savings of approximately $1.5 million to $2.0 million net to EXCO. The Company remains committed to restructuring its gathering and transportation contracts, which include contracts in the East Texas and North Louisiana regions with a significant amount of underutilized capacity and fee structures above current market rates.

Transforming EXCO into the lowest cost producer - EXCO continues to exercise fiscal discipline to transform itself into the lowest cost producer. EXCO has implemented several initiatives to reduce its general and administrative costs and lease operating costs, including significant reductions in its workforce. As a result of the reductions in force, the Company's total employee count decreased by 32% compared to the third quarter 2015 and 44% compared to year-end 2014. The general and administrative cost saving initiatives also included reductions in benefits, office expenses, software licenses and other costs. The Company expects its general and administrative expenses and lease operating expenses to continue to decrease in 2016 as it realizes a full year of cost savings from the reductions in force and other initiatives. EXCO was able to achieve top-tier safety performance for 2015 with a total recordable incident rate of 0.58 for employees and 0.34 for contractors, which is significantly below the industry average.

The Company's operational team is dedicated to the continuous improvement and innovation of well designs in order to maximize return on capital. The Company's improved well performance was the primary driver of the 184 Bcfe of upward revisions to its proved reserves during 2015. Enhanced well design and completion methods improved the well performance in the East Texas region and resulted in an increase in the estimated ultimate recoveries ("EUR") to 1.5 Bcf per 1,000 lateral feet for certain proved undeveloped Haynesville and Bossier shale locations, compared to 1.3 Bcf per 1,000 lateral feet as of year-end 2014. EXCO was able to achieve this improved performance while reducing the average drilling and completion capital by 28% on a lateral foot basis compared to year-end 2014. These capital reductions were the result of additional service cost reductions, design changes, performance improvements and other efficiencies that more than offset the use of significantly more proppant in the completion phase. The enhanced well designs and completion methods also resulted in an increase of the EUR to 2.0 Bcf per 1,000 lateral feet for certain proved undeveloped Haynesville shale locations in its core area of North Louisiana, compared to 1.6 Bcf per 1,000 lateral feet as of year-end 2014. EXCO's development of Haynesville shale assets in the North Louisiana region during 2016 will feature these enhanced completion methods. The Company has also seen sustained performance improvements in North Louisiana from the implementation of a full field compression program, which is expected to flatten its base decline and reduce future capital requirements.

Optimizing and repositioning the portfolio - EXCO has implemented a disciplined capital allocation approach to ensure the highest and best use of capital. The Company's capital is allocated based on the highest risk adjusted rates of return, including both the development of its oil and natural gas properties and liability management initiatives. EXCO's Board of Directors approved a 2016 capital budget of $103 million, including $70 million for the first half of 2016 focused on natural gas drilling and completion activities in North Louisiana and East Texas, which represent a reduction of $101 million, or 59%, versus the comparable 2015 period, and $33 million to fund field operations, land, capitalized corporate costs and other expenditures for the full year 2016. The Company's drilling and completion activities in North Louisiana achieve rates of return^(*) in excess of 35%, which are the highest returns for drilling opportunities in its portfolio. During 2016, the Company will continue to evaluate market conditions and recommend approval from the Board of Directors for the funding of drilling and completion activities, if any, for the second half of the year if the well returns exceed the internal rate of return hurdles and are consistent with EXCO's strategic objectives.

The Company allocates capital to drilling to generate value and to leasing and acquisitions to increase its drilling inventory. EXCO continues to evaluate acquisition opportunities that meet its strategic objectives to allow the Company to increase its drilling inventory and generate accretive returns throughout the commodity price cycle. The Company will also evaluate divestitures of assets that would allow it to redeploy capital 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				Q4	Fiscal
		12/31/15	9/30/15			12/31/14			12/31/15	12/31/14			2015	2015
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Rig counts (1)	#	3	4	(25	)	7	(57	)	4	9	(56	)	N/A	4

Net wells drilled (1)
North Louisiana	#	—	—	—		4.1	(100	)	1.7	20.8	(92	)	N/A	1.7
East Texas	#	2.7	2.4	13		—	100		10.0	3.9	156		N/A	9.8
South Texas	#	—	2.8	(100	)	4.8	(100	)	6.1	16.2	(62	)	N/A	6.1
Appalachia and other	#	—	—	—		0.5	(100	)	—	0.5	(100	)	N/A	—
Total net wells drilled	#	2.7	5.2	(48	)	9.4	(71	)	17.8	41.4	(57	)	N/A	17.6

Net wells turned-to-sales (1)
North Louisiana	#	—	—	—		4.5	(100	)	11.9	12.2	(2	)	N/A	11.9
East Texas	#	2.0	2.8	(29	)	1.9	5		5.8	3.9	49		N/A	5.8
South Texas	#	1.8	1.8	—		5.2	(65	)	11.0	13.5	(19	)	N/A	11.1
Appalachia and other	#	0.5	—	100		—	100		0.5	—	100		N/A	0.5
Total net wells turned-to-sales	#	4.3	4.6	(7	)	11.6	(63	)	29.2	29.6	(1	)	N/A	29.3

Daily production
North Louisiana	Mmcfe/d	174	197	(12	)	193	(10	)	202	225	(10	)	N/A	N/A
East Texas	Mmcfe/d	64	52	23		47	36		50	29	72		N/A	N/A
South Texas	Mmcfe/d	44	44	—		37	19		42	38	11		N/A	N/A
Appalachia and other (2)	Mmcfe/d	37	47	(21	)	63	(41	)	46	80	(43	)	N/A	N/A
Total daily production	Mmcfe/d	319	340	(6	)	340	(6	)	340	372	(9	)	315-325	335-345

Production
Oil	Mbbls	609	635	(4	)	527	16		2,342	2,236	5		655-675	2,300-2,400
Natural gas	Bcf	25.7	27.5	(7	)	28.1	(9	)	109.9	122.3	(10	)	25.1-25.9	108.5-111.5
Total production	Bcfe	29.3	31.3	(6	)	31.3	(6	)	124.0	135.7	(9	)	29.0-29.9	122.3-125.9

Capital Expenditures	$MM	35	64	(45	)	122	(71	)	277	424	(35	)	N/A	295-305


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


(2)	Includes 8 Mmcfe/d and 20 Mmcfe/d of production from Compass Production Partners, LP ("Compass") for the three months ended and the year ended December 31, 2014, respectively. EXCO sold its interest in Compass on October 31, 2014.

North Louisiana

Highlights:


•	Produced 174 Mmcfe per day, a decrease of 23 Mmcfe per day, or 12%, from the third quarter 2015, and a decrease of 19 Mmcfe per day, or 10%, from the fourth quarter 2014.


•	Enhanced completion methods resulted in an increase to 2.0 Bcf per 1,000 lateral feet from 1.6 Bcf per 1,000 lateral feet for proved undeveloped locations in the Haynesville shale within the Company's core area of North Louisiana during the fourth quarter 2015.


•	Implementing a modified well design featuring enhanced completion methods to drill and complete 9 gross (5.5 net) horizontal wells during 2016.

EXCO’s decrease in production compared to the third quarter 2015 was primarily the result of normal production declines since its most recent well in the region turned-to-sales in June 2015. The Company plans to operate an average of two drilling rigs to drill 9 gross (5.5 net) wells during the first six months of 2016 and complete 9 gross (5.5 net) wells for the full year 2016 at an average cost ranging from $6.7 million to $8.9 million per well with lateral lengths

ranging from 4,500 to 7,500 feet. The wells expected to be drilled in 2016 will feature similar completion methods that have proven to be successful in the Company's East Texas region, including the use of up to 2,700 lbs per lateral foot of proppant, modified well spacing and longer laterals. These improvements to well designs resulted in an increase to 2.0 Bcf per 1,000 lateral feet from 1.6 Bcf for proved undeveloped locations in the Haynesville shale within its core area of North Louisiana during the fourth quarter 2015. The Company is targeting rates of return^(*) in excess of 35% in this region during 2016.

EXCO has implemented several initiatives to enhance and manage its base production in the region. This includes a full field compression program in the Holly area that began in late 2015. EXCO has realized sustained performance improvement from this initiative as evidenced by a flattening of its base production decline as the overall gathering system pressure has been reduced from approximately 1,185 psi to the target of 500 psi.

East Texas

Highlights:


•	Produced 64 Mmcfe per day, an increase of 12 Mmcfe per day, or 23%, from the third quarter 2015, and an increase of 17 Mmcfe per day, or 36%, from the fourth quarter 2014.


•	Drilled 6 gross (2.7 net) operated horizontal Haynesville and Bossier wells and turned-to-sales 4 gross (2.0 net) operated horizontal wells in the Haynesville and Bossier shales during the fourth quarter 2015.


•	Enhanced completion methods resulted in an increase to 1.5 Bcf per 1,000 lateral feet from 1.3 Bcf for proved undeveloped locations in the Bossier shale in East Texas.

EXCO’s increase in production in East Texas compared to the third quarter 2015 was primarily the result of additional wells turned-to-sales. Development during the fourth quarter 2015 included 3 rigs that drilled 3 gross (1.2 net) wells in the Haynesville shale and 3 gross (1.5 net) wells in the Bossier shale. The wells turned-to-sales included 3 gross (1.5 net) wells in the Haynesville shale and 1 gross (0.5 net) well in the Bossier shale. The wells turned-to-sales in this region during 2015 featured enhanced completion methods that have continued to yield strong results. The well performance in the East Texas region resulted in an increase of the EUR to 1.5 Bcf per 1,000 lateral feet for certain proved undeveloped locations in both the Haynesville and Bossier shales compared to 1.3 Bcf per 1,000 lateral feet as of year-end 2014. EXCO believes there is the potential for additional upside in the EURs as more production history is established.

EXCO recognized certain reductions in drilling and completion costs including renegotiated rig and completion service contracts, as well as spacing modifications that allowed EXCO to utilize multi-well pad sites. The utilization of these multi-well pad sites allowed for reductions in road and location costs and lower mobilization costs due to closer proximity between well sites. In addition, EXCO's development in this region allowed it to realize economies of scale and increased drilling efficiency as the Company moved from an appraisal mode to a manufacturing mode. These changes have resulted in a decrease to $10.4 million for East Texas Haynesville wells that were drilled and expected to be completed in early 2016 despite the use of 90% more proppant in the completion phase, compared to average costs of $12.5 million for wells drilled in the region in 2014. The Company's average drilling time for the fourth quarter was 39 days with an average total measured depth of approximately 20,000 feet.

EXCO 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, in the third quarter 2015. As of December 31, 2015, the well continues to perform above expectations with a production rate of 10.5 Mmcfe per day on a 17/64th restricted choke with a flowing tubing pressure of 8,832 psi. The Company believes the continued strong results of this well show further upside for the undeveloped southern area of the Company's East Texas position. The Company currently has 112 undeveloped gross locations prospective for the Haynesville and Bossier shales in this area.

South Texas

Highlights:


•	Produced 7.3 Mboe per day consistent with the third quarter 2015 and an increase of 1.1 Mboe per day, or 19%, from the fourth quarter 2014.


•	Turned-to-sales 3 gross (1.8 net) operated horizontal wells.

EXCO’s production remained consistent compared to the third quarter 2015 primarily due to additional wells turned-to-sales that were offset by normal production declines in the region. Development included 2 gross (0.8 net) wells turned-to-sales in the Eagle Ford shale featuring enhanced completion methods. The average costs of the wells turned-to-sales in the Eagle Ford shale during the fourth quarter was approximately $6.1 million, with average lateral lengths of 8,900 feet and proppant of 2,300 lbs per lateral foot. The initial production rates from these wells averaged 780 Bbls per day. Development in the Buda formation included 1 gross (1.0 net) well turned-to-sales.

As a result of continued depressed oil prices, EXCO has no plans to drill in the region during 2016. 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 of this region.

Appalachia

Highlights:


•	Produced 37 Mmcfe per day, a decrease of 10 Mmcfe per day, or 21%, from the third quarter 2015, and a decrease of 17 Mmcfe per day, or 32%, from the fourth quarter 2014.

EXCO’s decrease in production compared to the third quarter 2015 was primarily attributable to shut-in production of approximately 11 Mmcfe per day during the fourth quarter from its Marcellus shale wells due to low regional market prices for natural gas. EXCO turned-to-sales 1 gross (0.5 net) well during the fourth quarter. The Company's position in the Marcellus shale requires low maintenance capital and approximately 84% of the acreage is held-by-production.

EXCO implemented reductions in force of field employees that primarily impacted the Appalachia region, reducing its field employee count in the area by 41% from 147 employees as of December 31, 2014 to 87 employees as of December 31, 2015. As a result of the reductions in force, the Company restructured its field organization to better align the operations personnel with the asset base and reduce its operating costs.

Proved Reserves

EXCO's proved reserves as of December 31, 2015, were 907 Bcfe with a SEC PV-10 of $402 million. For 2015, the SEC reference price was $2.59 per Mmbtu for natural gas and $50.28 per Bbl for oil. Each of the reference prices for oil and natural gas were adjusted for regional differentials. The SEC reference prices used were held flat for the life of the reserves. NYMEX PV-10 of proved reserves as of December 31, 2015 was $811 million^(*). See the "Non-GAAP Financial Measures" section of this press release for additional information.

Table 2: Summary of proved reserves

4Q 15; mixed measures



Factors	Unit	Oil		Natural gas (1)		Equivalent natural gas
Proved Developed Reserves	Mbbls/Mmcf/Mmcfe	12,056		364,932		437,268
Proved Undeveloped Reserves	Mbbls/Mmcf/Mmcfe	8,383		419,742		470,040
Total Proved Reserves	Mbbls/Mmcf/Mmcfe	20,439		784,674		907,308
The changes in reserves for the year are as follows:
January 1, 2015	Mbbls/Mmcf/Mmcfe	17,687		1,157,674		1,263,796
Purchases of reserves in place	Mbbls/Mmcf/Mmcfe	459		122		2,876
Discoveries and extensions	Mbbls/Mmcf/Mmcfe	7,602		152,473		198,085
Revisions of previous estimates (2):
Changes in price	Mbbls/Mmcf/Mmcfe	(2,821	)	(598,865	)	(615,791	)
Other factors	Mbbls/Mmcf/Mmcfe	(145	)	184,641		183,771
Sales of reserves in place	Mbbls/Mmcf/Mmcfe	(1	)	(1,445	)	(1,451	)
Production	Mbbls/Mmcf/Mmcfe	(2,342	)	(109,926	)	(123,978	)
December 31, 2015	Mbbls/Mmcf/Mmcfe	20,439		784,674		907,308


(1)	Beginning in 2015, EXCO began reporting its NGLs as a component of natural gas. Prior period information has been conformed to be consistent with current period information.

(2)

Revisions of previous estimates include both reserves in place at the beginning of the year and acquisitions and divestitures, if any, during the year. EXCO reclassified 223.0 Bcfe of Proved Undeveloped Reserves to unproved as a result of decreased commodity prices, which shortened the economic life of certain producing properties and resulted in the reclassification of Proved Undeveloped properties to unproved locations that became uneconomical when using prices prescribed by the SEC.

During 2015, EXCO added 198.1 Bcfe through discoveries and extensions, primarily as a result of its development programs of the Haynesville and Bossier shales in East Texas and the Eagle Ford shale in South Texas. The revisions of previous estimates included downward revisions to proved reserve quantities of 615.8 Bcfe as a result of decreased commodity prices, which shortened the economic life of certain producing properties and resulted in the reclassification of proved undeveloped properties to unproved locations as those properties became uneconomical when using prices prescribed by the SEC. The SEC reference natural gas price decreased 40% to $2.59 per Mmbtu for the year ended December 31, 2015 from $4.35 per Mmbtu for the year ended December 31, 2014, and the SEC reference oil price decreased 47% to $50.28 per Bbl for the year ended December 31, 2015 from $94.99 per Bbl for the year ended December 31, 2014. The revisions of previous estimates also included 183.8 Bcfe of upward revisions due to performance and other factors. This included 152.2 Bcfe of upward revisions in the North Louisiana region primarily due to modifications in the well design to incorporate more proppant and longer laterals. The upward revisions also included 36.7 Bcfe from the East Texas region primarily due to strong results in both the Haynesville and Bossier shales based on similar modifications in the well design. Reserves were reduced by 124.0 Bcfe as a result of production during the year.

Table 3: Summary of finding and development costs

4Q 15; mixed measures



		Year-to-Date
Factors	Unit	12/31/15	12/31/14
Development costs	$MM	215.2	350.4
Exploration costs	$MM	13.3	5.9
Total development and exploration (1)	$MM	228.5	356.3

Additions to proved developed reserves (2)	Bcfe	285.5	113.8

Finding and development costs	$/Mcfe	0.80	3.13


(1)	Excludes rig termination fees, field operations capital and other leasehold development costs that are not directly associated with future proved developed reserve additions.


(2)	Additions to proved developed reserves include both proved undeveloped reserves converted to proved developed reserves and unproved reserves converted to proved developed reserves.

Finding and development costs to convert reserves to proved developed reserves were $0.80 per Mcfe during 2015 compared to $3.13 per Mcfe during 2014. At December 31, 2014, EXCO had 40 gross (14.7 net) wells being completed or awaiting completion that were converted to proved developed reserves in 2015. This resulted in the finding and development costs to be significantly lower for the year-to-date 2015 as compared to year-to-date 2014. The Company's finding and development costs were $1.46 per Mcfe for 2015 and 2014 on a combined basis.



Financial Results

Table 4: Summary of operational earnings

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Q4	Fiscal
		12/31/15		9/30/15				12/31/14				12/31/15		12/31/14				2015	2015
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Guidance	Guidance
Operating revenues
Oil revenues	$MM	23		27		(15	)	37		(38	)	103		196		(47	)	N/A	N/A
Natural gas revenues	$MM	42		56		(25	)	91		(54	)	225		464		(51	)	N/A	N/A
Total revenues	$MM	65		84		(23	)	128		(49	)	328		660		(50	)	N/A	N/A
Realized oil prices	$/Bbl	37.63		43.22		(13	)	70.56		(47	)	43.89		87.80		(50	)	N/A	N/A
Oil price differentials	$/Bbl	(4.57	)	(3.37	)	36		(2.34	)	95		(4.78	)	(5.71	)	(16	)	(2.00-4.00)	(4.00-6.00)
Realized gas prices	$/Mcf	1.63		2.04		(20	)	3.22		(49	)	2.05		3.79		(46	)	N/A	N/A
Gas price differentials	$/Mcf	(0.65	)	(0.73	)	(11	)	(0.82	)	(21	)	(0.62	)	(0.65	)	(5	)	(0.60-0.70)	(0.55-0.65)

Derivative financial instruments
Cash settlements (payments)	$MM	40		32		25		13		208		129		(19	)	(779	)	N/A	N/A
Cash settlements (payments)	$/Mcfe	1.36		1.02		33		0.42		224		1.04		(0.14	)	(843	)	N/A	N/A

Costs and expenses
Oil and natural gas operating costs	$MM	12		13		(8	)	16		(25	)	54		64		(16	)	N/A	N/A
Production and ad valorem taxes	$MM	6		6		—		7		(14	)	23		30		(23	)	N/A	N/A
Gathering and transportation	$MM	25		24		4		25		—		99		102		(3	)	N/A	N/A
Oil and natural gas operating costs	$/Mcfe	0.41		0.40		3		0.50		(18	)	0.43		0.47		(9	)	0.40-0.45	0.40-0.45
Production and ad valorem taxes	$/Mcfe	0.21		0.19		11		0.22		(5	)	0.18		0.22		(18	)	0.15-0.20	0.15-0.20
Gathering and transportation	$/Mcfe	0.86		0.76		13		0.80		8		0.80		0.75		7		0.80-0.85	0.80-0.85
General and administrative (1)	$MM	14		12		17		14		—		52		61		(15	)	11-13	48-52

Operational earnings
Adjusted EBITDA (2)	$MM	50		62		(19	)	81		(38	)	238		391		(39	)	N/A	N/A
GAAP net income (loss) (3)	$MM	(66	)	(355	)	(81	)	81		(181	)	(1,192	)	121		N/M		N/A	N/A
Adjusted net income (loss) (2)	$MM	(9	)	(11	)	(18	)	(4	)	125		(51	)	17		(400	)	N/A	N/A
GAAP diluted shares outstanding	MM	278		273		2		271		3		274		268		2		N/A	N/A
Adjusted diluted shares outstanding	MM	278		273		2		271		3		274		268		2		N/A	N/A
GAAP diluted EPS	$/Share	(0.24	)	(1.30	)	(82	)	0.30		(180	)	(4.36	)	0.45		N/M		N/A	N/A
Adjusted diluted EPS	$/Share	(0.03	)	(0.04	)	(25	)	(0.02	)	50		(0.19	)	0.06		(417	)	N/A	N/A


(1)	Excludes equity-based compensation expenses of $3.2 million, $0.9 million and $0.6 million for the three months ended December 31, 2015, September 30, 2015 and December 31, 2014, respectively, and $7.2 million and $5.0 million for the years ended December 31, 2015 and 2014, respectively.


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


(3)	GAAP net income (loss) included impairments of oil and natural gas properties of $205 million and $339 million for the three months ended December 31, 2015 and September 30, 2015, respectively, and $1.2 billion for the year ended December 31, 2015.

EXCO’s decrease in adjusted EBITDA in the fourth quarter 2015 compared to the third quarter 2015 and for the year-to-date 2015 compared to 2014 was primarily due to lower revenues as a result of lower market prices for oil and natural gas and lower natural gas production. Oil differentials were negatively impacted by the narrowing of the premium of the LLS price index compared to the WTI price index in the fourth quarter 2015. The GAAP net loss during the fourth quarter and full year 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 of $205 million and $1.2 billion, respectively.

EXCO has implemented several initiatives to reduce its general and administrative costs, including reductions in its workforce during the second quarter 2014 and first and fourth quarters 2015. Excluding the impact of the severance costs, general and administrative expenses decreased 21% for year-to-date 2015 compared to 2014 (excluding equity-based compensation). General and administrative expenses for the quarter-to-date 2015 were above guidance due to $2.7 million of severance costs and the accrual of $1.8 million for the annual incentive payment to ESAS as a result of EXCO's performance rank under the plan during 2015. EXCO's performance rank, based on total shareholder return, was the highest in its peer group during the first nine months of the measurement period under the ESAS services and investment agreement. Excluding the impact of the severance costs and ESAS incentive accrual that were not contemplated in the development of the guidance, EXCO's general and administrative costs would have been below the low-end of guidance. EXCO's general and administrative costs are expected to continue to decrease in 2016 as it realizes a full year of cost savings from the reduction in force and initiatives such as the elimination of the employer matching program on its 401(k) plan and other benefits, as well as reductions in office expenses, software costs, and other initiatives.

Cash Flow Results

Table 5: Summary of key cash flow items

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Q4	Fiscal
		12/31/15		9/30/15				12/31/14				12/31/15		12/31/14				2015	2015
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Guidance	Guidance
Cash flow provided by (used in)
Operating activities	$MM	7		19		(63	)	4		75		134		362		(63	)	N/A	N/A
Investing activities	$MM	(45	)	(63	)	(29	)	15		(400	)	(301	)	(222	)	36		N/A	N/A
Financing activities	$MM	30		15		100		(21	)	(243	)	133		(145	)	(192	)	N/A	N/A
Net increase (decrease) in cash	$MM	(8	)	(29	)	(72	)	(2	)	300		(34	)	(4	)	750		N/A	N/A

Other key cash flow items
Adjusted operating cash flow (1)	$MM	30		38		(21	)	59		(49	)	149		309		(52	)	N/A	N/A
Free cash flow (1)	$MM	(41	)	(46	)	(11	)	(90	)	(54	)	(184	)	(30	)	513		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 in the fourth quarter compared to the third quarter 2015 was primarily the result of lower revenues and the timing of payments surrounding year-end. During the fourth quarter 2015, EXCO primarily used its cash flows from operations and borrowings under the Credit Agreement to fund drilling and development. EXCO's financing activities in the fourth quarter 2015 also included the issuance of the Fairfax Term Loan, repayments under its Credit Agreement, repurchases of the 2018 Notes, fees associated with the issuance of Second Lien Term Loans and payments on the Exchange Term Loan.

EXCO's decrease in operating cash flows for 2015 compared to 2014 was primarily the result of lower revenues and less favorable working capital conversions, offset by higher cash receipts on derivative contracts. During the year ended 2015, EXCO primarily used its cash flows from operations and borrowings under the Credit Agreement to fund drilling and development. EXCO's financing activities for year-to-date 2015 consisted of $300 million of proceeds received from the Fairfax Term Loan, $135 million of net repayments under its Credit Agreement, repurchases of the 2018 Notes, fees associated with the issuance of Second Lien Term Loans and payments on the Exchange Term Loan.

Liquidity Results

Table 6: Financial flexibility measures

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q4	Fiscal
		12/31/15	9/30/15			12/31/14			12/31/15	12/31/14			2015	2015
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Cash (1)	$MM	33	42	(21	)	70	(53	)	33	70	(53	)	N/A	N/A
Gross debt (2)	$MM	1,148	1,550	(26	)	1,452	(21	)	1,148	1,452	(21	)	N/A	N/A
Net debt	$MM	1,115	1,508	(26	)	1,382	(19	)	1,115	1,382	(19	)	N/A	N/A
Adjusted EBITDA (3)	$MM	50	62	(19	)	81	(38	)	238	391	(39	)	N/A	N/A
Cash interest expenses (4)	$MM	21	27	(22	)	26	(19	)	101	102	(1	)	28-30	109-114
Adjusted EBITDA/Interest (5)	x	2.38	2.30	3		3.12	(24	)	2.36	3.83	(38	)	N/A	N/A
Senior secured debt/LTM Adjusted EBITDA (5)	x	0.28	1.11	(75	)	0.52	(46	)	0.28	0.52	(46	)	N/A	N/A
Net debt/LTM Adjusted EBITDA	x	4.68	5.59	(16	)	3.53	33		4.68	3.53	33		N/A	N/A


(1)	Includes restricted cash of $21 million, $21 million and $24 million as of December 31, 2015, September 30, 2015 and December 31, 2014, respectively.


(2)	Represents total principal balance outstanding. See Table 7 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 $50.0 million. See Table 7 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 December 31, 2015, the ratio of consolidated EBITDAX to consolidated interest expense (as defined in the agreement including interest expense calculated in accordance with GAAP) was 2.4 to 1.0 and the ratio of senior secured indebtedness (excluding the Second Lien Term Loans) to consolidated EBITDAX (as defined in the agreement) was 0.3 to 1.0.

Table 7: Reconciliation of carrying value to principal

4Q 15; $MM



		12/31/15 (Actual)
Factors	Unit	Carrying value		Deferred reduction in carrying value (1)		Unamortized discount/deferred financing costs	Principal balance
Credit Agreement	$MM	67					67
Exchange Term Loan (1)	$MM	641		(241	)		400
Fairfax Term Loan	$MM	300					300
2018 Notes	$MM	157				1	158
2022 Notes	$MM	223					223
Deferred financing costs, net	$MM	(18	)			18	—
Total Debt	$MM	1,370					1,148

(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. EXCO determined that the future undiscounted cash flows from the Exchange Term Loan through its maturity were less than the carrying amounts of the retired 2018 Notes and 2022 Notes. As a result, the Company adjusted its carrying amount of the Exchange Term Loan to equal the total future cash payments, including interest and principal. Subsequently, 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 2016 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 8: Liquidity schedule

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q4	Fiscal
		12/31/15	9/30/15			12/31/14			12/31/15	12/31/14			2015	2015
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Borrowing base on revolver	$MM	375	600	(38	)	900	(58	)	375	900	(58	)	N/A	N/A
Amount drawn on revolver	$MM	67	300	(78	)	202	(67	)	67	202	(67	)	N/A	N/A
Letters of credit	$MM	7	7	—		7	—		7	7	—		N/A	N/A
Available for borrowing	$MM	301	293	3		691	(56	)	301	691	(56	)	N/A	N/A
Cash (1)	$MM	33	42	(21	)	70	(53	)	33	70	(53	)	N/A	N/A
Liquidity (2)	$MM	334	335	—		761	(56	)	334	761	(56	)	N/A	N/A


(1)	Includes restricted cash of $21 million, $21 million and $24 million as of December 31, 2015, September 30, 2015 and December 31, 2014, respectively.


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

EXCO's liquidity was $334 million as of year-end 2015. EXCO's 2016 capital budget is expected to exceed its cash flows from operations and the deficit is expected to be funded with borrowings under the Credit Agreement. The Company continues to evaluate and implement further cost reduction initiatives to mitigate the impact of low commodity prices on its cash flows and liquidity. The initiatives implemented during 2015 have included reductions in its workforce, reduced operating and capital expenditures through negotiations with key vendors and restructuring of commercial contracts including sales and firm transportation agreements. EXCO is currently evaluating transactions to further enhance its liquidity and capital structure including the issuance of additional indebtedness, the restructuring or repurchase of existing indebtedness, issuance of equity, cost reductions and divestitures of assets.

Risk Management Results

Table 9: Hedging position as of December 31, 2015

4Q 15; mixed measures

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

34,770

3.09

10,950

3.28

3,650

3.15

Oil

Fixed price swaps - WTI

Mbbl/$/Bbl

915

61.89

—

EXCO's derivative financial instruments were comprised of oil and natural gas swaps as of December 31, 2015. In the fourth quarter 2015, the Company converted all of its remaining 2016 three-way collars to fixed-price swaps covering 10,980 Bbtu of natural gas at an average price of $2.78 per Mmbtu.

The Company's derivative financial instruments covered approximately 68% of estimated production volumes for the full year 2015. Since year-end 2015, EXCO entered into swaption contracts that included fixed price swaps covering 6,700 Bbtu of natural gas at a price of $2.76 per Mmbtu for 2016 in exchange for an option on behalf of the counterparty to swap 7,300 Bbtu of natural gas at a price of $2.76 per Mmbtu for 2017. The Company also entered into fixed price swaps covering 12,200 Bbtu of natural gas at an average price of $2.45 per Mmbtu for 2016 and 1,800 Bbtu of natural gas at a price of $2.36 per Mmbtu for 2017. As a result, the Company currently has outstanding swap contracts covering 53,670 Bbtu of natural gas at an average price of $2.90 per Mmbtu for 2016.

In addition, the Company is proactively managing its credit risk in light of the current commodity price environment and has obtained financial assurances from certain customers, owners and other counterparties.

Other Developments

On February 26, 2016, EXCO was notified by the New York Stock Exchange (“NYSE”) of its noncompliance with continued listing standards because the average closing price of its common shares over a period of 30 consecutive trading days had fallen below $1.00 per share, which is the minimum average closing price per share required to maintain listing on the NYSE.

Under the NYSE rules, during the six-month period from the date of the NYSE notice, EXCO can regain compliance if the price per share of EXCO’s common shares on the last trading day of any calendar month within such period and the 30 trading day average price per common share for that month is at least $1.00. During this period, subject to EXCO’s compliance with other NYSE continued listing requirements, EXCO’s common shares will continue to be traded on the NYSE under the symbol “XCO” but will have an added designation of “.BC” to indicate the status of the common shares as below compliance.

EXCO intends to notify the NYSE of its intent to cure this noncompliance and is currently exploring its options for regaining compliance, including a potential reverse share split of EXCO’s common shares at a ratio of up to 1-for-10 as previously approved by EXCO’s shareholders. EXCO’s Board of Directors is currently evaluating whether to exercise its discretion to effect the reverse share split in an effort to regain compliance with the NYSE continued listing standards by increasing the market price of its common shares. In addition, EXCO is also currently evaluating transactions that could further enhance its liquidity and capital structure, including the issuance of additional indebtedness, further restructuring or repurchases of existing indebtedness, the issuance of equity, cost reductions, divestitures of assets, acquisitions or similar transactions, any of which could impact the trading price of EXCO’s common shares.

EXCO anticipates that the reverse share split, if completed, will cure the deficiency and the Company will regain compliance with the NYSE continued listing requirement. If EXCO is unable to regain compliance, the NYSE will initiate procedures to suspend and delist EXCO’s common shares.

The NYSE notification does not affect EXCO’s business operations or its Securities and Exchange Commission (“SEC”) reporting requirements and does not conflict with or cause an event of default under any of the Company’s material debt agreements. Furthermore, the NYSE notice is not related to the NYSE continued listing requirement that a listed company have a market capitalization of at least $50 million. Based on the closing price of the Company’s common shares on February 26, 2016, the Company’s market capitalization was approximately $280 million. A reverse share split would not be expected to affect the Company’s market capitalization.

Financial Data

The following financial statements are attached.



Attachment	Statements	Company	Period
1	Consolidated Balance Sheets	EXCO Resources, Inc.	12/31/2015
2	Consolidated Statements Of Operations	EXCO Resources, Inc.	12/31/2015
3	Consolidated Statements Of Cash Flows	EXCO Resources, Inc.	12/31/2015
4	EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations	EXCO Resources, Inc.	12/31/2015
5	GAAP Net Income (Loss) and Adjusted Net Income (Loss) Reconciliations	EXCO Resources, Inc.	12/31/2015

EXCO will host a conference call on Wednesday, March 2, 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#24918641. 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 March 30, 2016. Please call (800) 585-8367 and enter conference ID#24918641 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, estimates of costs and expenses, 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 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 after March 2, 2016 its annual Report on Form 10-K for the year ended December 31, 2015 and its other periodic filings with the SEC .



(in thousands)	December 31, 2015			December 31, 2014

Assets
Current assets:
Cash and cash equivalents	$	12,247		$	46,305
Restricted cash	21,220			23,970
Accounts receivable, net:
Oil and natural gas	37,236			81,720
Joint interest	22,095			65,398
Other	8,894			8,945
Derivative financial instruments	39,499			97,278
Inventory and other	8,610			7,150
Total current assets	149,801			330,766
Equity investments	40,797			55,985
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	115,377			276,025
Proved developed and undeveloped oil and natural gas properties	3,070,430			3,852,073
Accumulated depletion	(2,627,763		)	(2,414,461		)
Oil and natural gas properties, net	558,044			1,713,637
Other property and equipment, net	27,812			24,644
Deferred financing costs, net	8,408			14,617
Derivative financial instruments	6,109			2,138
Goodwill	163,155			163,155
Total assets	$	954,126		$	2,304,942
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	85,254		$	110,211
Revenues and royalties payable	106,163			152,651
Drilling advances	2,795			37,648
Accrued interest payable	7,846			26,265
Current portion of asset retirement obligations	845			1,769
Income taxes payable	—			—
Derivative financial instruments	16			892
Current portion of long-term debt	50,000			—
Total current liabilities	252,919			329,436
Long-term debt	1,320,279			1,430,516
Derivative financial instruments	—			—
Asset retirement obligations and other long-term liabilities	43,251			34,986
Commitments and contingencies	—			—
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,633,996 shares issued and 283,039,333 shares outstanding at December 31, 2015; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014	276			270
Additional paid-in capital	3,522,153			3,502,209
Accumulated deficit	(4,177,120		)	(2,984,860		)
Treasury shares, at cost; 594,663 at December 31, 2015 and 578,042 at December 31, 2014	(7,632		)	(7,615		)
Total shareholders’ equity	(662,323		)	510,004
Total liabilities and shareholders’ equity	$	954,126		$	2,304,942



	Three Months Ended									Year Ended
(in thousands, except per share data)	December 31, 2015			September 30, 2015			December 31, 2014			December 31, 2015			December 31, 2014
Revenues:				(Unaudited)
Total revenues	$	64,743		$	83,526		$	127,789		$	328,331		$	660,269
Costs and expenses:
Oil and natural gas operating costs	12,158			12,669			15,754			53,903			64,467
Production and ad valorem taxes	6,222			5,944			6,908			22,630			29,859
Gathering and transportation	25,078			23,743			25,101			99,321			101,574
Depletion, depreciation and amortization	39,266			52,013			62,128			215,426			263,569
Impairment of oil and natural gas properties	205,323			339,393			—			1,215,370			—
Accretion of discount on asset retirement obligations	579			574			605			2,277			2,690
General and administrative	17,591			13,393			15,019			58,818			65,920
(Gain) loss on divestitures and other operating items	(657		)	(228		)	(1,067		)	461			5,315
Total costs and expenses	305,560			447,501			124,448			1,668,206			533,394
Operating income (loss)	(240,817		)	(363,975		)	3,341			(1,339,875		)	126,875
Other income (expense):
Interest expense, net	(25,260		)	(27,761		)	(24,178		)	(106,082		)	(94,284		)
Gain on derivative financial instruments	21,442			37,348			102,561			75,869			87,665
Gain on restructuring and extinguishment of debt	193,276			—			—			193,276			—
Other income	3			21			65			122			241
Equity income (loss)	(14,239		)	(152		)	(376		)	(15,691		)	172
Total other income (expense)	175,222			9,456			78,072			147,494			(6,206		)
Income (loss) before income taxes	(65,595		)	(354,519		)	81,413			(1,192,381		)	120,669
Income tax expense	—			—			—			—			—
Net income (loss)	$	(65,595	)	$	(354,519	)	$	81,413		$	(1,192,381	)	$	120,669
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(0.24	)	$	(1.30	)	$	0.30		$	(4.36	)	$	0.45
Weighted average common shares outstanding	277,995			273,348			271,053			273,621			268,258
Diluted:
Net income (loss)	$	(0.24	)	$	(1.30	)	$	0.30		$	(4.36	)	$	0.45
Weighted average common shares and common share equivalents outstanding	277,995			273,348			271,053			273,621			268,376



	Year Ended December 31,
(in thousands)	2015			2014
Operating Activities:
Net income (loss)	$	(1,192,381	)	$	120,669
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	215,426			263,569
Equity-based compensation expense	7,198			4,962
Accretion of discount on asset retirement obligations	2,277			2,690
Impairment of oil and natural gas properties	1,215,370			—
(Income) loss from equity investments	15,691			(172		)
Gain on derivative financial instruments	(75,869		)	(87,665		)
Cash settlements (payments) of derivative financial instruments	128,800			(18,991		)
Amortization of deferred financing costs and discount on debt issuance	16,994			12,055
Other non-operating items	(32		)	(17		)
Gain on restructuring and extinguishment of debt	(193,276		)	—
Effect of changes in:
Restricted cash with related party	(2,100		)	—
Accounts receivable	88,610			52,007
Other current assets	434			(2,609		)
Accounts payable and other current liabilities	(93,115		)	15,595
Net cash provided by operating activities	134,027			362,093
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(317,590		)	(391,776		)
Property acquisitions	(7,608		)	(10,790		)
Proceeds from disposition of property and equipment	7,397			187,655
Restricted cash	4,850			(3,400		)
Net changes in advances to joint ventures	10,663			(5,026		)
Equity investments and other	1,455			1,749
Net cash used in investing activities	(300,833		)	(221,588		)
Financing Activities:
Borrowings under credit agreements	165,000			100,000
Repayments under credit agreements	(300,000		)	(964,970		)
Proceeds received from issuance of 2022 Notes	—			500,000
Repurchases of 2018 Notes	(12,008		)	—
Proceeds received from issuance of Fairfax Term Loan	300,000			—
Payment on Exchange Term Loan	(8,827		)	—
Proceeds from issuance of common shares, net	9,693			271,773
Payment of common share dividends	(164		)	(41,060		)
Deferred financing costs and other	(20,946		)	(10,426		)
Net cash used in financing activities	132,748			(144,683		)
Net decrease in cash	(34,058		)	(4,178		)
Cash at beginning of period	46,305			50,483
Cash at end of period	$	12,247		$	46,305
Supplemental Cash Flow Information:
Cash interest payments	$	117,463		$	91,735
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation	$	3,428		$	5,498
Capitalized interest	12,040			20,060
Issuance of common stock for director services	150			235
Debt eliminated upon sale of Compass	—			(83,246		)



	Three Months Ended									Year Ended
(in thousands)	December 31, 2015			September 30, 2015			December 31, 2014			December 31, 2015			December 31, 2014
Net income (loss)	$	(65,595	)	$	(354,519	)	$	81,413		$	(1,192,381	)	$	120,669
Interest expense	25,260			27,761			24,178			106,082			94,284
Income tax expense	—			—			—			—			—
Depletion, depreciation and amortization	39,266			52,013			62,128			215,426			263,569
EBITDA(1)	$	(1,069	)	$	(274,745	)	$	167,719		$	(870,873	)	$	478,522
Accretion of discount on asset retirement obligations	579			574			605			2,277			2,690
Impairment of oil and natural gas properties	205,323			339,393			—			1,215,370			—
Other items impacting comparability	2,463			641			714			9,172			11,836
Gain on restructuring and extinguishment of debt	(193,276		)	—			—			(193,276		)	—
Equity (income) loss	14,239			152			376			15,691			(172		)
Gain on derivative financial instruments	(21,442		)	(37,348		)	(102,561		)	(75,869		)	(87,665		)
Cash settlements (payments) on derivative financial instruments	39,823			31,938			13,196			128,800			(18,991		)
Equity-based compensation expense	3,153			926			592			7,198			4,962
Adjusted EBITDA (1)	$	49,793		$	61,531		$	80,641		$	238,490		$	391,182
Interest expense	(25,260		)	(27,761		)	(24,178		)	(106,082		)	(94,284		)
Income tax expense	—			—			—			—			—
Amortization of deferred financing costs and discount	5,911			4,108			2,164			16,994			12,055
Other operating items impacting comparability	(2,482		)	(654		)	(723		)	(9,204		)	(11,853		)
Changes in working capital	(20,791		)	(18,572		)	(54,176		)	(6,171		)	64,993
Net cash provided by operating activities	$	7,171		$	18,652		$	3,728		$	134,027		$	362,093



	Three Months Ended						Year Ended
(in thousands)	December 31, 2015		September 30, 2015		December 31, 2014		December 31, 2015		December 31, 2014
Cash flow from operations, GAAP	$	7,171	$	18,652	$	3,728	$	134,027	$	362,093
Net change in working capital	20,791		18,572		54,176		6,171		(64,993		)
Other operating items impacting comparability	2,463		641		714		9,172		11,836
Adjusted operating cash flow, non-GAAP measure (2)	$	30,425	$	37,865	$	58,618	$	149,370	$	308,936



	Three Months Ended									Year Ended
(in thousands)	December 31, 2015			September 30, 2015			December 31, 2014			December 31, 2015			December 31, 2014
Cash flow from operations, GAAP	$	7,171		$	18,652		$	3,728		$	134,027		$	362,093
Less: Additions to oil and natural gas properties, gathering assets and equipment	(47,882		)	(65,108		)	(94,040		)	(317,590		)	(391,776		)
Free cash flow, non-GAAP measure (3)	$	(40,711	)	$	(46,456	)	$	(90,312	)	$	(183,563	)	$	(29,683	)

(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																		Year Ended
	December 31, 2015						September 30, 2015						December 31, 2014						December 31, 2015						December 31, 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	$	(65,595	)				$	(354,519	)				$	81,413					$	(1,192,381	)				$	120,669
Adjustments:
Gain on derivative financial instruments	(21,442		)				(37,348		)				(102,561		)				(75,869		)				(87,665		)
Gain on restructuring and extinguishment of debt	(193,276		)				—						—						(193,276		)				—
Cash settlements (payments) on derivatives	39,823						31,938						13,196						128,800						(18,991		)
Impairment of oil and natural gas properties	205,323						339,393						—						1,215,370						—
Adjustments included in equity (income) loss	14,018						195						296						15,049						(1,453		)
Other items impacting comparability	2,463						641						714						9,172						11,836
Deferred finance cost amortization acceleration	3,972						2,007						—						8,744						3,471
Income taxes on above adjustments (1)	(20,352		)				(134,730		)				35,342						(443,196		)				37,121
Adjustment to deferred tax asset valuation allowance (2)	26,238						141,808						(32,565		)				476,952						(48,268		)
Total adjustments, net of taxes	56,767						343,904						(85,578		)				1,141,746						(103,949		)
Adjusted net income (loss)	$	(8,828	)				$	(10,615	)				$	(4,165	)				$	(50,635	)				$	16,720

Net income (loss), GAAP (3)	$	(65,595	)	$	(0.24	)	$	(354,519	)	$	(1.30	)	$	81,413		$	0.30		$	(1,192,381	)	$	(4.36	)	$	120,669		$	0.45
Adjustments shown above (3)	56,767			0.21			343,904			1.26			(85,578		)	(0.32		)	1,141,746			4.17			(103,949		)	(0.39		)
Dilution attributable to equity-based payments (4)	—			—			—			—			—			—			—			—			—			—
Adjusted net income (loss) (5)	$	(8,828	)	$	(0.03	)	$	(10,615	)	$	(0.04	)	$	(4,165	)	$	(0.02	)	$	(50,635	)	$	(0.19	)	$	16,720		$	0.06

Common share and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding	277,995						273,348						271,053						273,621						268,258
Dilutive stock options	—						—						—						—						—
Dilutive restricted shares and restricted share units	—						—						—						—						118
Dilutive warrants	—						—						—						—						—
Shares used to compute diluted EPS for adjusted net income	277,995						273,348						271,053						273,621						268,376


(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.

Other Non-GAAP Financial Measures

Certain non-GAAP (as defined below) financial measures are set forth in this release. A non-GAAP financial measure is a numerical measure of a company’s performance that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with generally accepted accounting principles in the United States (“GAAP”). SEC PV-10 and NYMEX PV-10 as used in this release are considered non-GAAP financial measures. EXCO believes that SEC PV-10, while not a financial measure in accordance with U.S. GAAP, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions due to tax characteristics which can differ significantly among comparable companies. The total Standardized Measure, a measure recognized under GAAP, as of December 31, 2015 was $402.1 million. The Standardized Measure represents the SEC PV-10 after giving effect to income taxes, and is calculated in accordance with the Financial Accounting Standards Board Accounting Standards Codification 932, Extractive Activities, Oil and Gas. There is no difference in Standardized Measure and SEC PV-10 for all years presented in this release as the impacts of net operating loss carry-forwards eliminated future income taxes.

The NYMEX PV-10 as disclosed in this release differs from the Standardized Measure, a GAAP measure, primarily due to the oil and natural gas prices utilized in the determination of future net cash flows. EXCO believes that NYMEX PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. There is not a corresponding GAAP measure for NYMEX PV-10 of proved reserves calculated using prices other than those prescribed by the SEC. Accordingly, it is not practicable to reconcile NYMEX PV-10 as of December 31, 2015 to the Standardized Measure.

(*)

NYMEX PV-10 and rates of return included in this release were based on NYMEX futures prices as of December 31, 2015, including natural gas prices per Mmbtu of $2.49 for 2016, $2.79 for 2017, $2.91 for 2018, $3.03 for 2019, $3.18 for 2020, $3.31 for 2021, $3.46 for 2022, $3.61 for 2023, $3.74 for 2024, $3.88 for 2025 and $4.00 thereafter, and oil prices per Bbl of $41.44 for 2016, $46.47 for 2017, $49.70 for 2018, $52.19 for 2019, $53.77 for 2020, $54.75 for 2021, $55.29 for 2022, $55.71 for 2023, and $57.50 thereafter.

Attachment

Statements

Consolidated Balance Sheets

EXCO Resources, Inc.