EXCO RESOURCES INC - FORM 8-K - EX-99.1 - Q4 2016 EARNINGS RELEASE

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Exhibit 99.1

EXCO Resources, Inc.

12377 Merit Drive, Suite 1700, Dallas, Texas 75251

Investor Relations Contact: Tyler Farquharson (214) 368-2084

EXCO RESOURCES, INC. REPORTS FOURTH QUARTER AND FULL YEAR

2016 RESULTS

DALLAS, TEXAS, March 16, 2017…EXCO Resources, Inc. (NYSE: XCO) (“EXCO” or the "Company") today announced fourth quarter and full year operating and financial results for 2016.



Highlights


•	EXCO delivered operational and financial results within or better than guidance for fourth quarter 2016 and full year 2016.


•	Produced 263 Mmcfe per day, or 24 Bcfe, for fourth quarter 2016 and produced 285 Mmcfe per day, or 104 Bcfe, for full year 2016, within guidance.

•

GAAP net loss was $35 million, or $0.12 per diluted share, and adjusted net loss, a non-GAAP measure, was $2 million, or $0.00 per diluted share, for fourth quarter 2016. GAAP net loss was primarily due to unrealized losses on derivative financial instruments and impairments of equity investments. GAAP net loss was $225 million, or $0.81 per diluted share, and adjusted net loss was $41 million, or $0.15 per diluted share for full year 2016.


•	Adjusted EBITDA, a non-GAAP measure, was $26 million for fourth quarter 2016, 4% above adjusted EBITDA for third quarter 2016, primarily due to higher commodity prices partially offset by lower production. Adjusted EBITDA was $96 million for full year 2016, 59% below adjusted EBITDA for full year 2015, primarily due to lower commodity prices and production.


•	Proved reserves were 477 Bcfe and Standardized Measure and SEC PV-10, a non-GAAP measure, calculated using the prices prescribed by the Securities and Exchange Commission ("SEC") were $311 million as of December 31, 2016. Proved reserves were 1.5 Tcfe and PV-10 based on NYMEX futures prices, a non-GAAP measure, as of December 31, 2016 ("NYMEX PV-10") was $970 million^(*).

•

On March 15, 2017, EXCO executed a series of transactions that significantly improved its liquidity and capital structure. This included the issuance of $300 million 1.5 Lien Notes, as defined below, and the exchange of $683 million Second Lien Term Loans for a like amount of 1.75 Lien Term Loans, both as defined below, providing the Company with the option to pay interest in cash, common shares or additional indebtedness.

Key Developments

Strategic plan update

EXCO's strategic plan continues to focus on 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 the 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 remains committed to improving its financial flexibility and enhancing long-term value for shareholders through the continued execution of its comprehensive consensual restructuring program (the “Restructuring Program”). The focus is to establish a sustainable capital structure that provides the Company with the liquidity necessary to execute its business plan.

In March 2017, the Company closed a series of transactions that significantly improved its capital structure, including the issuance of $300 million in aggregate principal amount of senior secured 1.5 lien notes due March 20, 2022 ("1.5 Lien Notes"), exchanges of $683 million in aggregate principal amount of senior secured second lien term loans due October 26, 2020 ("Second Lien Term Loans") for a like amount of senior secured 1.75 lien term loans due October 26, 2020 ("1.75 Lien Term Loans"), and the issuance of warrants. The 1.5 Lien Notes and 1.75 Lien Term Loans provide the option, subject to certain limitations, to pay interest in cash, common shares, or additional indebtedness. The Company is required to obtain shareholder approval to permit the exercisability of the warrants and issuance of common shares in connection with the payment of interest on the 1.5 Lien Notes and 1.75 Lien Term Loans. See further information related to these transactions in the Form 8-K filed with the SEC on March 15, 2017.

The proceeds from the issuance of the 1.5 Lien Notes were primarily utilized for the repayment of the entire amount outstanding under EXCO's credit agreement ("Credit Agreement"), transaction fees and general corporate purposes. The Credit Agreement was amended to reduce the borrowing base to $150 million, permit the issuance of the 1.5 Lien Notes and the exchanges of Second Lien Term Loans, and modify certain financial covenants. Liquidity, which represents cash plus the unused borrowing base under the Credit Agreement, improved by $116 million on a pro forma basis compared to December 31, 2016, after incorporating the impact of the transactions. The option to pay interest in common shares on the 1.5 Lien Notes and 1.75 Lien Term Loans has the potential to reduce annual cash interest payments by approximately $109 million, subject to certain restrictions. EXCO anticipates the transactions will enhance its capital structure, provide the optionality to improve future cash flows and establish structural liquidity to implement its business plan. The reduction in cash interest expenses will increase the cash flows from operations available to fund its future capital expenditures and acquisitions, if any.

Transforming EXCO into the lowest cost producer - EXCO continues to exercise fiscal discipline to transform itself into the lowest cost producer. Lease operating expenses decreased by 35% in 2016 compared to 2015 primarily due to the renegotiation of saltwater disposal contracts, modifications to chemical programs, enhanced use of well site automation, optimization of work schedules and less workover activity. In addition, in the Appalachia region, the Company divested most of its conventional assets, which had the highest lease operating expenses per Mcfe in its portfolio. The divestitures contributed to reduced field headcount in the region by 85% since December 31, 2015.

GAAP general and administrative expenses decreased by 17% in 2016 compared to 2015. Adjusted general and administrative expenses (excluding equity-based compensation, restructuring and severance costs), a non-GAAP measure, decreased 39% in 2016 compared to 2015. The Company's cost reduction efforts and recent divestitures have resulted in a decrease in total employee headcount to approximately 180 persons, a decrease of approximately 40% since December 31, 2015 and approximately 70% since December 31, 2014.

EXCO is dedicated to the continuous improvement and innovation of well designs in order to maximize its return on capital. The Company reduced its drilling and completion costs through modifications to well designs, renegotiated contracts with vendors, and other efficiencies. In addition, the Company improved well performance through the use of extended laterals and increased use of proppant while reducing both capital and operating costs.

The Company's enhanced completion methods in North Louisiana achieved strong results during 2016, including a 13% increase in the estimated ultimate recovery ("EUR") to an average of 2.3 Bcf per 1,000 lateral feet for certain proved developed locations in the Haynesville shale within the Company's core area of North Louisiana. The Company drilled three gross wells in North Louisiana with lateral lengths of approximately 4,300 feet during 2016 featuring completion methods that included the use of approximately 2,700 lbs of proppant per lateral foot for an average total well cost of $5.9 million, representing a 13% decrease compared to wells drilled in this region with similar lateral lengths in prior year despite increased proppant use. The Company also drilled three gross wells in North Louisiana during 2016 with lateral lengths of approximately 7,600 feet featuring completion methods that included the use of approximately 2,650 lbs of proppant per lateral foot for an average total well cost of $8.8 million. The Company will continue to focus on operational initiatives to enhance its well designs including the use of an average of 3,500 lbs of proppant per lateral foot for completions during 2017 and the potential to extended laterals up to 10,000 feet.

In the Company's East Texas region, the two most recent wells turned-to-sales in the southern area continue to exceed expectations and resulted in a 73% increase to an average EUR of 2.6 Bcf per 1,000 lateral feet as compared to December 31, 2015.

Optimizing and repositioning the portfolio - The Company continues to execute its disciplined capital allocation program to ensure the highest and best uses of capital, including the completion of a series of asset divestitures as part of its portfolio optimization initiative. In October 2016, the Company closed a sale of its interests in shallow conventional assets located in West Virginia following the sale of its interests in shallow conventional assets located in Pennsylvania in July 2016. EXCO retained all rights to other formations below the conventional depths in the Appalachia region including the Upper Devonian, Marcellus and Utica shales. The Company is also evaluating other divestitures of assets, including its assets in South Texas, to generate capital that can be deployed to projects with high rates of return. EXCO's technical team is performing an evaluation of prospective locations to unlock additional value in its portfolio, including the dry gas window of the Utica shale in Pennsylvania and the Bossier shale in North Louisiana. The Company drilled an appraisal well in the Bossier shale in North Louisiana with enhanced completion methods during first quarter 2017 to further evaluate the potential of the formation.

Operational Results

Table 1: Summary of operating activities and operational results

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q4	Fiscal
		12/31/16	9/30/16			12/31/15			12/31/16	12/31/15			2016	2016
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Rig counts (1)	#	—	—	—		3	(100	)	1	4	(75	)	—	1

Net wells drilled (1)
North Louisiana	#	—	—	—		—	—		5.2	1.7	206		N/A	N/A
East Texas	#	—	—	—		2.7	(100	)	—	10.0	(100	)	N/A	N/A
South Texas	#	—	—	—		—	—		—	6.1	(100	)	N/A	N/A
Appalachia and other	#	—	—	—		—	—		—	—	—		N/A	N/A
Total net wells drilled	#	—	—	—		2.7	(100	)	5.2	17.8	(71	)	—	5.2

Net wells turned-to-sales (1)
North Louisiana	#	—	2.7	(100	)	—	—		5.2	11.9	(56	)	N/A	N/A
East Texas	#	—	—	—		2.0	(100	)	3.6	5.8	(38	)	N/A	N/A
South Texas	#	—	—	—		1.8	(100	)	—	11.0	(100	)	N/A	N/A
Appalachia and other	#	0.4	—	100		0.5	(20	)	0.4	0.5	(20	)	N/A	N/A
Total net wells turned-to-sales	#	0.4	2.7	(85	)	4.3	(91	)	9.2	29.2	(68	)	—	8.8

Daily production
North Louisiana	Mmcfe/d	149	159	(6	)	174	(14	)	151	202	(25	)	N/A	N/A
East Texas	Mmcfe/d	60	69	(13	)	64	(6	)	67	50	34		N/A	N/A
South Texas	Mmcfe/d	27	27	—		44	(39	)	31	42	(26	)	N/A	N/A
Appalachia and other	Mmcfe/d	27	33	(18	)	37	(27	)	36	46	(22	)	N/A	N/A
Total daily production	Mmcfe/d	263	288	(9	)	319	(18	)	285	340	(16	)	255-265	280-300

Production
Oil	Mbbls	381	391	(3	)	609	(37	)	1,769	2,342	(24	)	335-355	1,720-1,740
Natural gas	Bcf	21.9	24.1	(9	)	25.7	(15	)	93.8	109.9	(15	)	21.5-22.3	92.2-99.4
Total production	Bcfe	24.2	26.5	(9	)	29.3	(17	)	104.4	124.0	(16	)	23.5-24.4	102.5-109.8

Capital expenditures	$MM	8	14	(43	)	35	(77	)	78	277	(72	)	N/A	85


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

North Louisiana

Highlights:


•	Produced 149 Mmcfe per day, a decrease of 10 Mmcfe per day, or 6%, from third quarter 2016, and a decrease of 25 Mmcfe per day, or 14%, from fourth quarter 2015.


•	Enhanced completion methods resulted in a 13% increase in the EUR to an average of 2.3 Bcf per 1,000 lateral feet for certain proved developed locations in the Haynesville shale within the Company's core area of North Louisiana, reflecting improved performance of the wells turned-to-sales during 2016.

EXCO’s decrease in production compared to the third quarter 2016 was primarily the result of normal production declines since its most recent well in the region turned-to-sales in July 2016.

The Company plans to drill 5 gross (3.9 net) wells during first quarter 2017 that will be completed and turned-to-sales in second and third quarter 2017. This includes 4 gross (3.0 net) wells in the Haynesville shale with lateral lengths ranging from 4,500 feet to 7,500 feet and 1 gross (0.8 net) well in the Bossier shale with a lateral length of 7,500 feet. The development program during first quarter 2017 will continue to build on the successful modifications to the

Company's well design, which includes enhanced completions using an average of 3,500 lbs of proppant per lateral foot.

The cost per well for the wells drilled during first quarter 2017 is expected to be $6.8 million to $9.3 million in the Haynesville shale based on the lateral length and $11.2 million in the Bossier shale. EXCO is targeting rates of return ranging from 57% to 100% for these Haynesville shale wells based on the lateral length and a flat natural gas price of $3.00 per Mmbtu. EXCO's development plans in this region subsequent to the first quarter 2017 may feature drilling extended lateral length wells up to 10,000 feet. The Company’s inventory in its core area of North Louisiana includes 103 gross (37 net) operated undeveloped locations in the Haynesville shale based on lateral lengths ranging from 4,500 feet to 10,000 feet.

The Company will evaluate the results of the Bossier shale well featuring enhanced completion methods to assess the potential for future development of Bossier shale locations in North Louisiana. If the results are successful, the Company's extensive infrastructure could allow for efficient development of its inventory of 168 gross (78 net) operated undeveloped locations in the Bossier shale in North Louisiana based on average lateral lengths of 7,500 feet.

East Texas

Highlights:


•	Produced 60 Mmcfe per day, a decrease of 9 Mmcfe per day, or 13%, from third quarter 2016, and a decrease of 4 Mmcfe per day, or 6%, from fourth quarter 2015.


•	EXCO's most recent two wells drilled in the southern portion of the region continued to exhibit strong performance and resulted in a 73% increase to an average EUR of 2.6 Bcf per 1,000 lateral feet as compared to December 31, 2015.

EXCO’s decrease in production compared to the third quarter 2016 was primarily due to natural production declines since its most recent well in the region turned-to-sales in March 2016.

EXCO's development activities in the East Texas region during first quarter 2017 will primarily include the participation in wells operated by others. This includes the development of a well by a third-party that will satisfy a continuous drilling obligation on certain acreage in the southern portion of the region. The Company remains encouraged by the potential to develop its 122 gross (30 net) operated undeveloped locations within this southern portion of the East Texas region.

South Texas

Highlights:


•	Produced 4.5 Mboe per day consistent with third quarter 2016 and a decrease of 2.8 Mboe per day, or 39%, from fourth quarter 2015.

Production remained consistent with the third quarter 2016 as a result of lower downtime. EXCO is evaluating the potential divestiture of its properties in the South Texas region and does not anticipate allocating development capital to this region during 2017.

Appalachia

Highlights:


•	Produced 27 Mmcfe per day, a decrease of 6 Mmcfe per day, or 18%, from third quarter 2016, and a decrease of 10 Mmcfe per day, or 27%, from fourth quarter 2015.


•	Turned-to-sales 1 gross (0.4 net) Marcellus shale well during fourth quarter 2016.

EXCO’s decrease in production compared to the third quarter 2016 was primarily attributable to the sale of its shallow conventional assets located in West Virginia on October 3, 2016, and was impacted by 0.6 Bcfe shut-in due to low regional natural gas prices in Appalachia during early fourth quarter 2016. However, regional differentials in Appalachia improved in late 2016 from NYMEX less $1.52 per Mcfe during September to NYMEX less $0.45 per Mcfe during December. As a result, predominantly all of the production previously shut-in was turned on-line as prices improved in fourth quarter 2016.

In recent years, the Company has limited its development of the Marcellus shale due to wide regional natural gas price differentials. These differentials began to narrow in late 2016 and have the potential to be favorably impacted by the expansion of infrastructure and other sources of demand for natural gas in the Northeast region as early as 2018. EXCO has an extensive inventory of undeveloped locations prospective for the Marcellus and Utica shales that have potential to provide attractive rates of return in an improved commodity price environment. EXCO’s position in the Appalachia region requires low maintenance capital and approximately 90% of the acreage is held-by-production, providing the optionality for future development activities with minimal cost to hold the position. The Company is currently evaluating the potential of its acreage in the Utica shale and is encouraged by its ongoing technical analysis and successful results from other operators in the region. EXCO owns Utica shale rights in approximately 40,000 net acres predominantly located in the dry gas window. The Company expects to participate in certain Utica shale wells operated by others during 2017.



Financial Results

Table 2: Summary of operational earnings

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Q4	Fiscal
		12/31/16		9/30/16				12/31/15				12/31/16		12/31/15				2016	2016
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Guidance	Guidance
Operating revenues
Oil revenues	$MM	18		16		13		23		(22	)	67		103		(35	)	N/A	N/A
Natural gas revenues	$MM	54		55		(2	)	42		29		181		226		(20	)	N/A	N/A
Total oil and natural gas revenues	$MM	72		71		1		65		11		249		329		(24	)	N/A	N/A
Realized oil prices	$/Bbl	46.27		41.47		12		37.63		23		38.05		43.89		(13	)	N/A	N/A
Oil price differentials	$/Bbl	(2.86	)	(3.57	)	(20	)	(4.57	)	(37	)	(4.30	)	(4.78	)	(10	)	(3.00-4.00)	(3.50-5.50)
Realized gas prices	$/Mcf	2.48		2.27		9		1.64		51		1.93		2.06		(6	)	N/A	N/A
Gas price differentials	$/Mcf	(0.50	)	(0.54	)	(7	)	(0.63	)	(21	)	(0.51	)	(0.61	)	(16	)	(0.50-0.60)	(0.50-0.60)

Derivative financial instruments
Cash settlements (payments)	$MM	1		5		(80	)	40		(98	)	39		129		(70	)	N/A	N/A
Cash settlements (payments)	$/Mcfe	0.04		0.18		(78	)	1.36		(97	)	0.37		1.04		(64	)	N/A	N/A

Costs and expenses
Oil and natural gas operating costs	$MM	9		9		—		12		(25	)	35		54		(35	)	N/A	N/A
Production and ad valorem taxes	$MM	2		4		(50	)	6		(67	)	15		23		(35	)	N/A	N/A
Gathering and transportation	$MM	27		28		(4	)	25		8		106		99		7		N/A	N/A
Oil and natural gas operating costs	$/Mcfe	0.36		0.33		9		0.41		(12	)	0.33		0.43		(23	)	0.35-0.40	0.35-0.40
Production and ad valorem taxes	$/Mcfe	0.09		0.14		(36	)	0.21		(57	)	0.15		0.18		(17	)	0.15-0.20	0.15-0.20
Gathering and transportation	$/Mcfe	1.10		1.06		4		0.86		28		1.02		0.80		28		1.05-1.10	1.00-1.05
General and administrative (1)	$MM	10		9		11		14		(29	)	34		52		(35	)	9-10	30-35

Operational earnings
Adjusted EBITDA (2)	$MM	26		25		4		47		(45	)	96		233		(59	)	N/A	N/A
GAAP net income (loss) (3)	$MM	(35	)	51		(169	)	(66	)	(47	)	(225	)	(1,192	)	(81	)	N/A	N/A
Adjusted net income (loss) (2)	$MM	(2	)	(6	)	(67	)	(10	)	(80	)	(41	)	(54	)	(24	)	N/A	N/A
GAAP diluted shares outstanding	MM	280		281		—		278		1		279		274		2		N/A	N/A
Adjusted diluted shares outstanding	MM	280		280		—		278		1		279		274		2		N/A	N/A
GAAP diluted EPS	$/Share	(0.12	)	0.18		(167	)	(0.24	)	(50	)	(0.81	)	(4.36	)	(81	)	N/A	N/A
Adjusted diluted EPS	$/Share	—		(0.02	)	(100	)	(0.04	)	(100	)	(0.15	)	(0.20	)	(25	)	N/A	N/A


(1)	Excludes equity-based compensation expenses of $0.2 million, $1.4 million and $3.2 million for the three months ended December 31, 2016, September 30, 2016 and December 31, 2015, respectively, and $14.8 million and $7.2 million for the years ended December 31, 2016 and 2015, 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 for the three months ended December 31, 2015, and $161 million and $1.2 billion for the years ended December 31, 2016 and 2015, respectively.

EXCO's GAAP net income decreased from $51 million in third quarter 2016 to a GAAP net loss of $35 million in fourth quarter 2016. The net loss was primarily due to unrealized losses on derivative financial instruments and impairments of equity investments. Net income in third quarter 2016 included a net gain on extinguishment of debt of $57 million.

EXCO’s increase in Adjusted EBITDA compared to the third quarter 2016 was primarily due to higher commodity prices partially offset by lower production. The Company's general and administrative expenses during fourth quarter 2016 were impacted by $4 million of legal and advisory fees associated with the Company's Restructuring Program.

Table 3: 2017 Guidance

Q1 17; mixed measures

The Company is currently incorporating the impact of the recent financing transactions into its development plans for the remainder of 2017. The Company's guidance for first quarter 2017 includes the following:



		Q1
		2017
Factors	Unit	Guidance
Production
Oil	Mbbls	(300-320)
Natural gas	Bcf	(19.4-20.1)
Total production	Bcfe	(21.2-22.1)
Total daily production	Mmcfe/d	(235-245)

Realized price differentials
Oil price differentials	$/Bbl	(3.00-4.00)
Gas price differentials	$/Mcf	(0.50-0.60)

Financial results
Oil and natural gas operating costs	$/Mcfe	0.40-0.45
Production and ad valorem taxes	$/Mcfe	0.15-0.20
Gathering and transportation	$/Mcfe	1.20-1.25
General and administrative (1)	$MM	9-10

Capital expenditures	$MM	26


(1)	Excludes equity-based compensation expense.

Cash Flow Results

Table 4: Summary of key cash flow items

Historical vs. guidance; mixed measures



		Quarter-to-Date										Year-to-Date						Q4	Fiscal
		12/31/16		9/30/16				12/31/15				12/31/16		12/31/15				2016	2016
Factors	Unit	Actual		Actual		%		Actual		%		Actual		Actual		%		Guidance	Guidance
Cash flow provided by (used in)
Operating activities	$MM	3		(50	)	(106	)	7		(57	)	—		134		(100	)	N/A	N/A
Investing activities	$MM	1		(13	)	(108	)	(45	)	(102	)	(55	)	(301	)	(82	)	N/A	N/A
Financing activities	$MM	1		39		(97	)	30		(97	)	52		133		(61	)	N/A	N/A
Net increase (decrease) in cash	$MM	6		(24	)	(125	)	(8	)	(175	)	(3	)	(34	)	(91	)	N/A	N/A

Other key cash flow items
Adjusted operating cash flow (1)	$MM	12		11		9		28		(57	)	35		144		(76	)	N/A	N/A
Free cash flow (1)	$MM	(6	)	(65	)	(91	)	(41	)	(85	)	(80	)	(184	)	(57	)	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 in fourth quarter 2016 compared to third quarter 2016 was primarily the result of more favorable working capital conversions. During fourth quarter 2016, EXCO primarily used its cash flows from operations to fund limited development activities and acquisitions of certain assets. EXCO's financing activities

in fourth quarter 2016 included $14 million of borrowings under the Credit Agreement primarily utilized for payments related to the Second Lien Term Loans.

EXCO's decrease in operating cash flows for 2016 compared to 2015 was primarily the result of lower revenues, lower cash receipts on derivative contracts and less favorable working capital conversions. During 2016, EXCO primarily used its borrowings under the Credit Agreement to fund drilling and development. EXCO's financing activities during 2016 consisted of $161 million of net borrowings under the Credit Agreement, partially offset by payments of $51 million related to the Second Lien Term Loans and $53 million of cash payments used to repurchase a portion of its 2018 Notes and 2022 Notes at a discount to the principal amount.

Liquidity Results

Table 5: Financial flexibility measures

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q4	Fiscal
		12/31/16	9/30/16			12/31/15			12/31/16	12/31/15			2016	2016
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Cash (1)	$MM	20	22	(9	)	33	(39	)	20	33	(39	)	N/A	N/A
Gross debt (2)	$MM	1,130	1,116	1		1,148	(2	)	1,130	1,148	(2	)	N/A	N/A
Net debt (3)	$MM	1,110	1,094	1		1,115	—		1,110	1,115	—		N/A	N/A
Adjusted EBITDA (4)	$MM	26	25	4		47	(45	)	96	233	(59	)	N/A	N/A
Cash interest expenses (5)	$MM	16	16	—		21	(24	)	66	101	(35	)	16-18	65-70
Adjusted EBITDA/Interest (6)	x	1.63	1.56	4		2.24	(27	)	1.45	2.31	(37	)	N/A	N/A
Senior secured debt/LTM Adjusted EBITDA (5)	x	2.39	1.84	30		0.29	724		2.39	0.29	724		N/A	N/A
Net debt/LTM Adjusted EBITDA	x	11.56	9.35	24		4.79	141		11.56	4.79	141		N/A	N/A


(1)	Includes restricted cash of $11 million, $18 million and $21 million as of December 31, 2016, September 30, 2016 and December 31, 2015, respectively.


(2)	Represents total principal balance outstanding. See Table 8 below for reconciliation to carrying value.


(3)	Net debt represents principal amount of outstanding debt less cash and cash equivalents and restricted cash.


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

(5)

Cash interest expenses exclude the amortization of debt issuance costs, discount on notes and capitalized interest. In addition, cash payments under the Exchange Term Loan are not considered interest expense per Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 470-60, Troubled Debt Restructuring by Debtors ("ASC 470-60") and are excluded from the cash interest expenses amounts shown. EXCO's payments on the Exchange Term Loan were approximately $50.0 million during 2016. See Table 8 below for additional information on the accounting treatment of the Exchange Term Loan.

(6)

These ratios differ in certain respects from the calculations of comparable measures in the Credit Agreement. As of December 31, 2016, the ratio of consolidated EBITDAX to consolidated interest expense (as defined in the agreement including interest expense calculated in accordance with GAAP) was 1.47 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 2.45 to 1.0. On March 15, 2017, the Company amended the Credit Agreement, which included modifications to the financial covenants. See further information related to the amendment to the Credit Agreement in the Form 8-K filed with the SEC on March 15, 2017.

Table 6: Liquidity schedule

Historical vs. guidance; mixed measures



		Quarter-to-Date							Year-to-Date				Q4	Fiscal
		12/31/16	9/30/16			12/31/15			12/31/16	12/31/15			2016	2016
Factors	Unit	Actual	Actual	%		Actual	%		Actual	Actual	%		Guidance	Guidance
Borrowing capacity on revolver	$MM	285	300	(5	)	375	(24	)	285	375	(24	)	N/A	N/A
Amount drawn on revolver	$MM	229	215	7		67	242		229	67	242		N/A	N/A
Letters of credit	$MM	10	10	—		7	43		10	7	43		N/A	N/A
Available for borrowing	$MM	46	75	(39	)	301	(85	)	46	301	(85	)	N/A	N/A
Cash (1)	$MM	20	22	(9	)	33	(39	)	20	33	(39	)	N/A	N/A
Liquidity (2)	$MM	66	97	(32	)	334	(80	)	66	334	(80	)	N/A	N/A


(1)	Includes restricted cash of $11 million, $18 million and $21 million as of December 31, 2016, September 30, 2016 and December 31, 2015, respectively.

(2)

Liquidity is calculated as the available borrowing capacity under the Credit Agreement plus cash and cash equivalents and restricted cash. The borrowing base under the Credit Agreement was $325 million as of December 31, 2016. EXCO aggregate exposure could not exceed $285 million at December 31, 2016, including letters of credit. Therefore, the limitation on the aggregate exposure of the lenders of $285 million is used in the calculation of liquidity as it is more representative of EXCO's available borrowing capacity under the Credit Agreement.

EXCO's liquidity was $66 million as of year-end 2016. Subsequent to December 31, 2016, EXCO executed a series of transactions that improved its liquidity and capital structure, including the issuance of the 1.5 Lien Notes and exchanges of the Second Lien Term Loans for 1.75 Lien Term Loans. As a result, EXCO repaid its outstanding balance on the Credit Agreement and increased its liquidity by approximately $116 million on a pro forma basis compared to December 31, 2016. EXCO's borrowing base was reduced to $150 million in connection with the transactions.

The 1.5 Lien Notes and 1.75 Lien Term Loans provide the option, subject to certain limitations, to pay interest in cash, common shares, or additional indebtedness. The Company is required to obtain shareholder approval to permit the exercisability of the warrants and issuance of common shares in connection with the payment of interest on the 1.5 Lien Notes and 1.75 Lien Term Loans. If the Company is not able to the obtain shareholder approval to pay interest in common shares, it does not believe it will be able to comply with all of the covenants under the Credit Agreement or have sufficient liquidity to conduct its business operations based on existing conditions and estimates during the next twelve months. In particular, the amended ratio of consolidated EBITDAX to consolidated interest expense excludes payments in common shares or additional indebtedness on the 1.5 Lien Notes and 1.75 Lien Term Loans. Therefore, the receipt of shareholder approval to pay interest through the issuance of common shares is essential to the Company's ability to maintain compliance with this covenant.

The Company intends to seek approval for these transactions through its annual meeting of shareholders or at a special meeting of shareholders called for such purpose within the six-month period required by the 1.5 Lien Notes and 1.75 Lien Term Loans. There is no assurance such transactions will occur. If the shareholder approval is obtained, the Company's plan would be to pay interest on the 1.5 Lien Notes and 1.75 Lien Term Loans in common shares during this period, and the Company would expect to have sufficient liquidity and maintain compliance with its debt covenants during the next twelve months. See further information on the risks related to EXCO’s indebtedness and its ability to continue as a going concern in the Company’s periodic filings with the SEC.

The following table shows EXCO's liquidity as of December 31, 2016 and on a pro forma basis to incorporate the impact of the transactions:

Table 7: Pro Forma Liquidity

4Q 16; $MM



		12/31/16
Factors	Unit	Actual	Pro forma adjustments		Pro forma
Borrowing capacity on revolver	$MM	285	(135	)	150
Amount drawn on revolver	$MM	229	(229	)	—
Letters of credit	$MM	10	—		10
Available for borrowing	$MM	46	—		140
Cash (1) (2)	$MM	20	22		42
Liquidity	$MM	66			182


(1)	Includes restricted cash of $11 million.


(2)	Pro forma cash was reduced by $13 million of cash paid to investors of the 1.5 Lien Notes and lenders of the 1.75 Lien Term Loans electing to receive cash in lieu of warrants, $12 million of estimated transaction fees and expenses associated with the financing transactions, and repayments of additional borrowings of $25 million under the Credit Agreement subsequent to December 31, 2016.

Table 8: Reconciliation of carrying value to principal

4Q 16; $MM



		12/31/16 (Actual)
Factors	Unit	Carrying value		Deferred reduction in carrying value (1)		Unamortized discount/deferred financing costs	Principal balance
Credit Agreement	$MM	229					229
Exchange Term Loan (1)	$MM	590		(190	)		400
Fairfax Term Loan	$MM	300					300
2018 Notes	$MM	131				1	132
2022 Notes	$MM	70					70
Deferred financing costs, net	$MM	(12	)			12	—
Total Debt	$MM	1,309					1,130

(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. 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 maturities 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.

Risk Management Results

Table 9: Hedging position as of December 31, 2016

4Q 16; mixed measures

Twelve Months Ended

12/31/17

12/31/18

Factors

Unit

Volume

Strike Price

Volume

Strike Price

Natural gas

Fixed price swaps - Henry Hub

Bbtu/$/Mmbtu

38,300

3.02

3,650

3.15

Collars - Henry Hub

Bbtu

10,950

—

Sold call options

$/Mmbtu

3.28

—

Purchased put options

$/Mmbtu

2.87

—

Oil

Fixed price swaps - WTI

Mbbl/$/Bbl

183

50.00

—

The Company's derivative financial instruments covered approximately 66% and 57% of production volumes for fourth quarter and full year 2016, respectively.

Proved Reserves

EXCO's proved reserves as of December 31, 2016, were 477 Bcfe with a Standardized Measure and SEC PV-10 of $311 million. The SEC reference prices at December 31, 2016 were $2.48 per Mmbtu for natural gas and $42.75 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. All of the Company's proved undeveloped reserves were classified as unproved at December 31, 2016 due to the uncertainty regarding the Company's availability of capital required to develop these reserves. The issuance of the 1.5 Lien Notes and exchange of the Second Lien Term Loans subsequent to the preparation of the Company's proved reserves at December 31, 2016 provided additional capital that may be utilized to fund a development program and the Company may report upward revisions to its proved reserves in future periods. NYMEX PV-10 as of December 31, 2016 was $970 million^(*)and proved reserves based on this methodology were 1.5 Tcfe. See the "Other Non-GAAP Financial Measures" section of this press release for additional information on SEC PV-10 and NYMEX PV-10.

Table 10: Summary of proved reserves

4Q 16; mixed measures



Factors	Unit	Oil		Natural gas		Equivalent natural gas
Proved Developed Reserves	Mbbls/Mmcf/Mmcfe	10,168		415,719		476,727
Proved Undeveloped Reserves	Mbbls/Mmcf/Mmcfe	—		—		—
Total Proved Reserves	Mbbls/Mmcf/Mmcfe	10,168		415,719		476,727
The changes in reserves for the year are as follows:
January 1, 2016	Mbbls/Mmcf/Mmcfe	20,439		784,674		907,308
Purchases of reserves in place	Mbbls/Mmcf/Mmcfe	—		552		552
Discoveries and extensions	Mbbls/Mmcf/Mmcfe	—		16,381		16,381
Revisions of previous estimates (1):
Changes in price	Mbbls/Mmcf/Mmcfe	(2,061	)	(55,748	)	(68,114	)
Other factors	Mbbls/Mmcf/Mmcfe	(5,165	)	(208,714	)	(239,704	)
Sales of reserves in place	Mbbls/Mmcf/Mmcfe	(1,276	)	(27,597	)	(35,253	)
Production	Mbbls/Mmcf/Mmcfe	(1,769	)	(93,829	)	(104,443	)
December 31, 2016	Mbbls/Mmcf/Mmcfe	10,168		415,719		476,727

(1)

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 428 Bcfe of Proved Undeveloped Reserves to unproved due to the uncertainty regarding the financing required to develop these reserves. This decrease was partially offset by approximately 188 Bcfe of upward revisions due to performance and other factors.

During 2016, EXCO's revisions of previous estimates included downward revisions to its proved reserve quantities of 240 Bcfe. These downward revisions were primarily the result of 428 Bcfe of the proved undeveloped reserves reclassified to unproved during the first quarter of 2016 due to the uncertainty regarding the financing required to develop these reserves that existed on March 31, 2016. These reserves remained classified as unproved since the uncertainty regarding the Company's availability of capital required to develop these reserves still existed at December 31, 2016. The revisions of previous estimates included downward revisions to proved reserve quantities of 68 Bcfe as a result of decreased commodity prices, which shortened the economic life of certain producing properties when using prices prescribed by the SEC. The SEC reference natural gas price decreased 4% to $2.48 per Mmbtu for the year ended December 31, 2016 from $2.59 per Mmbtu for the year ended December 31, 2015, and the SEC reference oil price decreased 15% to $42.75 per Bbl for the year ended December 31, 2016 from $50.28 per Bbl for the year ended December 31, 2015. These decreases were partially offset by 188 Bcfe of upward revisions due to performance and other factors. This included 99 Bcfe of upward revisions in the Marcellus shale primarily due to narrower regional differentials, reductions in operating expenses, and improved performance as wells have exhibited shallower declines than previously forecasted. The upward revisions also reflect a reduction in operating expenses in other areas, primarily North Louisiana and South Texas, which increased reserves by 51 Bcfe and 24 Bcfe, respectively. In addition, the upward revisions in North Louisiana reflect improved performance of certain Haynesville shale wells that the Company

turned-to-sales during 2016. These wells featured enhanced completion methods including more proppant per lateral foot.

Table 11: Summary of finding and development costs

4Q 16/15; mixed measures



		Year-to-Date
Factors	Unit	12/31/16	12/31/15
Development costs	$MM	62.3	215.2
Exploration costs	$MM	—	13.3
Total development and exploration (1)	$MM	62.3	228.5

Additions to proved developed reserves (2)	Bcfe	77.9	285.5

Finding and development costs	$/Mcfe	0.80	0.80


(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. Quantities are based on respective year-end quantities, adjusted for production, and include performance and other revisions.

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. The development and exploration costs spent prior to 2015 on the wells converted to proved developed reserves in 2015 impacted the Company's finding and development costs per Mcfe. Excluding the impact from timing of these completions, finding and development costs per Mcfe would have decreased from 2016 to 2015 on the Company's operated wells due to reduced costs and improved well performance.

(*)

NYMEX PV-10 was based on NYMEX futures prices as of December 30, 2016, including natural gas prices per Mmbtu of $3.63 for 2017, $3.14 for 2018, $2.87 for 2019, $2.88 for 2020, $2.90 for 2021, $2.93 for 2022, $3.02 for 2023, $3.16 for 2024 and $3.31 thereafter, and oil prices per Bbl of $56.35 for 2017, $56.52 for 2018, $56.07 for 2019, $56.06 for 2020, $56.23 for 2021, $56.56 for 2022 and $57.04 thereafter.

Financial Data

The following financial statements are attached.



Attachment	Statements	Company	Period
1	Consolidated Balance Sheets	EXCO Resources, Inc.	12/31/2016
2	Consolidated Statements Of Operations	EXCO Resources, Inc.	12/31/2016
3	Consolidated Statements Of Cash Flows	EXCO Resources, Inc.	12/31/2016
4	EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations	EXCO Resources, Inc.	12/31/2016
5	GAAP Net Income (Loss) and Adjusted Net Loss Reconciliations	EXCO Resources, Inc.	12/31/2016
6	Other Non-GAAP Financial Measures	EXCO Resources, Inc.	12/31/2016

EXCO will host a conference call on Monday, March 20, 2017 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# 64386533. 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 April 15, 2017. Please call (800) 585-8367 and enter conference ID# 64386533 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 Tyler Farquharson, EXCO’s Vice President, Chief Financial Officer 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, 2015, filed with the SEC on March 2, 2016 and after March 16, 2017 its annual Report on Form 10-K for the year ended December 31, 2016 and its other periodic filings with the SEC.



(in thousands)	December 31, 2016			December 31, 2015

Assets
Current assets:
Cash and cash equivalents	$	9,068		$	12,247
Restricted cash	11,150			21,220
Accounts receivable, net:
Oil and natural gas	52,674			37,236
Joint interest	25,905			22,095
Other	3,813			8,894
Derivative financial instruments	—			39,499
Inventory and other	8,007			8,610
Total current assets	110,617			149,801
Equity investments	24,365			40,797
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized	97,080			115,377
Proved developed and undeveloped oil and natural gas properties	2,939,923			3,070,430
Accumulated depletion	(2,702,245		)	(2,627,763		)
Oil and natural gas properties, net	334,758			558,044
Other property and equipment, net	23,661			27,812
Deferred financing costs, net	4,376			8,408
Derivative financial instruments	482			6,109
Goodwill	163,155			163,155
Total assets	$	661,414		$	954,126
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	54,762		$	88,049
Revenues and royalties payable	120,845			106,163
Accrued interest payable	4,701			7,846
Current portion of asset retirement obligations	344			845
Income taxes payable	—			—
Derivative financial instruments	27,711			16
Current portion of long-term debt	50,000			50,000
Total current liabilities	258,363			252,919
Long-term debt	1,258,538			1,320,279
Deferred income taxes	2,802			—
Derivative financial instruments	464			—
Asset retirement obligations and other long-term liabilities	13,153			43,251
Commitments and contingencies	—			—
Shareholders’ equity:
Common shares, $0.001 par value; 780,000,000 authorized shares; 283,568,268 shares issued and 282,973,605 shares outstanding at December 31, 2016; 283,633,996 shares issued and 283,039,333 shares outstanding at December 31, 2015	284			276
Additional paid-in capital	3,537,815			3,522,153
Accumulated deficit	(4,402,373		)	(4,177,120		)
Treasury shares, at cost; 594,663 at December 31, 2016 and 2015	(7,632		)	(7,632		)
Total shareholders’ equity	(871,906		)	(662,323		)
Total liabilities and shareholders’ equity	$	661,414		$	954,126



	Three Months Ended									Year Ended
(in thousands, except per share data)	December 31, 2016			September 30, 2016			December 31, 2015			December 31, 2016			December 31, 2015
Revenues:	(Unaudited)			(Unaudited)			(Unaudited)
Oil and natural gas	$	71,917		$	70,862		$	65,111		$	248,649		$	329,258
Purchased natural gas and marketing (1)	7,017			6,324			5,430			22,352			26,442
Total revenues	78,934			77,186			70,541			271,001			355,700
Costs and expenses:
Oil and natural gas operating costs	8,774			8,797			12,158			34,609			53,903
Production and ad valorem taxes	2,072			3,811			6,222			15,380			22,630
Gathering and transportation	26,632			27,979			25,078			106,460			99,321
Purchased natural gas (1)	6,284			6,586			5,798			23,557			27,369
Depletion, depreciation and amortization	11,987			15,910			39,266			75,982			215,426
Impairment of oil and natural gas properties	—			—			205,323			160,813			1,215,370
Accretion of discount on asset retirement obligations	204			325			579			2,210			2,277
General and administrative	10,074			10,746			17,591			48,700			58,818
Other operating items	303			(1,110		)	(657		)	24,239			461
Total costs and expenses	66,330			73,044			311,358			491,950			1,695,575
Operating income (loss)	12,604			4,142			(240,817		)	(220,949		)	(1,339,875		)
Other income (expense):
Interest expense, net	(16,252		)	(16,997		)	(25,260		)	(70,438		)	(106,082		)
Gain (loss) on derivative financial instruments	(22,505		)	8,209			21,442			(34,137		)	75,869
Gain on restructuring and extinguishment of debt	83			57,421			193,276			119,457			193,276
Other income	6			12			3			43			122
Equity loss	(7,608		)	(823		)	(14,239		)	(16,432		)	(15,691		)
Total other income (expense)	(46,276		)	47,822			175,222			(1,507		)	147,494
Income (loss) before income taxes	(33,672		)	51,964			(65,595		)	(222,456		)	(1,192,381		)
Income tax expense	1,027			1,028			—			2,802			—
Net income (loss)	$	(34,699	)	$	50,936		$	(65,595	)	$	(225,258	)	$	(1,192,381	)
Earnings (loss) per common share:
Basic:
Net income (loss)	$	(0.12	)	$	0.18		$	(0.24	)	$	(0.81	)	$	(4.36	)
Weighted average common shares outstanding	280,119			279,873			277,995			279,287			273,621
Diluted:
Net income (loss)	$	(0.12	)	$	0.18		$	(0.24	)	$	(0.81	)	$	(4.36	)
Weighted average common shares and common share equivalents outstanding	280,119			281,045			277,995			279,287			273,621

(1)

EXCO has revised its presentation of third party natural gas purchases and sales to report these costs and revenues on a gross basis in the accompanying statements of operations in accordance with FASB ASC 605, Revenue Recognition, beginning in third quarter 2016. Third party purchases and sales are now reported gross as "Purchased natural gas" expenses and "Purchased natural gas and marketing" revenues, respectively. These revisions have been made to prior period information to conform to current period presentation.



	Year Ended December 31,
(in thousands)	2016			2015

Operating Activities:
Net loss	$	(225,258	)	$	(1,192,381	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred income tax expense	2,802			—
Depletion, depreciation and amortization	75,982			215,426
Equity-based compensation expense	14,778			7,198
Accretion of discount on asset retirement obligations	2,210			2,277
Impairment of oil and natural gas properties	160,813			1,215,370
Loss from equity investments	16,432			15,691
(Gain) loss on derivative financial instruments	34,137			(75,869		)
Cash receipts of derivative financial instruments	39,149			128,800
Amortization of deferred financing costs and discount on debt issuance	9,256			16,994
Other non-operating items	24,073			(32		)
Gain on restructuring and extinguishment of debt	(119,457		)	(193,276		)
Effect of changes in:
Restricted cash with related party	2,100			(2,100		)
Accounts receivable	(19,763		)	88,610
Other current assets	(1,716		)	434
Accounts payable and other current liabilities	(15,952		)	(93,115		)
Net cash provided by (used in) operating activities	(414		)	134,027
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment	(79,393		)	(317,590		)
Property acquisitions	(1,032		)	(7,608		)
Proceeds from disposition of property and equipment	14,349			7,397
Restricted cash	7,970			4,850
Net changes in advances to joint ventures	3,097			10,663
Equity investments and other	—			1,455
Net cash used in investing activities	(55,009		)	(300,833		)
Financing Activities:
Borrowings under credit agreements	404,897			165,000
Repayments under credit agreements	(243,797		)	(300,000		)
Repurchases of senior unsecured notes	(53,298		)	(12,008		)
Proceeds received from issuance of Fairfax Term Loan	—			300,000
Payments on Exchange Term Loan	(50,695		)	(8,827		)
Proceeds from issuance of common shares, net	—			9,693
Payments of common share dividends	(91		)	(164		)
Deferred financing costs and other	(4,772		)	(20,946		)
Net cash provided by financing activities	52,244			132,748
Net decrease in cash	(3,179		)	(34,058		)
Cash at beginning of period	12,247			46,305
Cash at end of period	$	9,068		$	12,247
Supplemental Cash Flow Information:
Cash interest payments	$	68,134		$	117,463
Income tax payments	—			—
Supplemental non-cash investing and financing activities:
Capitalized equity-based compensation	$	752		$	3,428
Capitalized interest	5,213			12,040



	Three Months Ended									Year Ended
(in thousands)	December 31, 2016			September 30, 2016			December 31, 2015			December 31, 2016			December 31, 2015
Net income (loss)	$	(34,699	)	$	50,936		$	(65,595	)	$	(225,258	)	$	(1,192,381	)
Interest expense	16,252			16,997			25,260			70,438			106,082
Income tax expense	1,027			1,028			—			2,802			—
Depletion, depreciation and amortization	11,987			15,910			39,266			75,982			215,426
EBITDA(1)	$	(5,433	)	$	84,871		$	(1,069	)	$	(76,036	)	$	(870,873	)
Accretion of discount on asset retirement obligations	204			325			579			2,210			2,277
Impairment of oil and natural gas properties	—			—			205,323			160,813			1,215,370
Other items impacting comparability	—			(1,062		)	(252		)	23,636			3,889
Gain on restructuring and extinguishment of debt	(83		)	(57,421		)	(193,276		)	(119,457		)	(193,276		)
Equity loss	7,608			823			14,239			16,432			15,691
(Gain) loss on derivative financial instruments	22,505			(8,209		)	(21,442		)	34,137			(75,869		)
Cash receipts of derivative financial instruments	1,052			4,709			39,823			39,149			128,800
Equity-based compensation expense	220			1,417			3,153			14,778			7,198
Adjusted EBITDA (1)	$	26,073		$	25,453		$	47,078		$	95,662		$	233,207
Interest expense	(16,252		)	(16,997		)	(25,260		)	(70,438		)	(106,082		)
Current income tax expense	—			—			—			—			—
Amortization of deferred financing costs and discount	2,006			2,251			5,911			9,256			16,994
Other operating items impacting comparability and non-operating items	5			(21		)	233			437			(3,921		)
Changes in working capital	(8,506		)	(60,351		)	(20,791		)	(35,331		)	(6,171		)
Net cash provided by operating activities	$	3,326		$	(49,665	)	$	7,171		$	(414	)	$	134,027



	Three Months Ended								Year Ended
(in thousands)	December 31, 2016		September 30, 2016			December 31, 2015			December 31, 2016			December 31, 2015
Cash flow from operations, GAAP	$	3,326	$	(49,665	)	$	7,171		$	(414	)	$	134,027
Net change in working capital	8,506		60,351			20,791			35,331			6,171
Other operating items impacting comparability	—		—			(252		)	402			3,889
Adjusted operating cash flow, non-GAAP measure (2)	$	11,832	$	10,686		$	27,710		$	35,319		$	144,087



	Three Months Ended									Year Ended
(in thousands)	December 31, 2016			September 30, 2016			December 31, 2015			December 31, 2016			December 31, 2015
Cash flow from operations, GAAP	$	3,326		$	(49,665	)	$	7,171		$	(414	)	$	134,027
Less: Additions to oil and natural gas properties, gathering assets and equipment	(8,938		)	(15,492		)	(47,882		)	(79,393		)	(317,590		)
Free cash flow, non-GAAP measure (3)	$	(5,612	)	$	(65,157	)	$	(40,711	)	$	(79,807	)	$	(183,563	)

(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 accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash impairments of assets, equity-based compensation, income or losses from equity method investments and other operating items impacting comparability. In previous periods, the Company added back severance costs in the determination of Adjusted EBITDA. As a result of a reduction in workforce that occurred in the second quarter 2016, management reassessed this measurement and determined it is no longer considered non-recurring. Accordingly, all periods for which Adjusted EBITDA is presented include severance costs.

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 1.5 Lien Notes, the indenture governing the 2018 Notes, the indenture governing the 2022 Notes and the term loan credit agreement governing the 1.75 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 indentures and the term loan credit agreements.

(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. All periods for which Adjusted operating cash flow is presented include severance costs.


(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, 2016						September 30, 2016						December 31, 2015						December 31, 2016						December 31, 2015
(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	$	(34,699	)				$	50,936					$	(65,595	)				$	(225,258	)				$	(1,192,381	)
Adjustments:
(Gain) loss on derivative financial instruments	22,505						(8,209		)				(21,442		)				34,137						(75,869		)
Gain on restructuring and extinguishment of debt	(83		)				(57,421		)				(193,276		)				(119,457		)				(193,276		)
Cash receipts of derivative financial instruments	1,052						4,709						39,823						39,149						128,800
Impairment of oil and natural gas properties	—						—						205,323						160,813						1,215,370
Adjustments included in equity loss	6,810						25						14,018						14,701						15,049
Other items impacting comparability	—						(1,062		)				(252		)				23,636						3,889
Deferred finance cost amortization acceleration	228						417						3,972						1,658						8,744
Income taxes on above adjustments (1)	(12,205		)				24,616						(19,266		)				(61,855		)				(441,083		)
Adjustment to deferred tax asset valuation allowance (2)	14,496						(19,758		)				26,238						91,784						476,952
Total adjustments, net of taxes	32,803						(56,683		)				55,138						184,566						1,138,576
Adjusted net loss (5)	$	(1,896	)				$	(5,747	)				$	(10,457	)				$	(40,692	)				$	(53,805	)

Net income (loss), GAAP (3)	$	(34,699	)	$	(0.12	)	$	50,936		$	0.18		$	(65,595	)	$	(0.24	)	$	(225,258	)	$	(0.81	)	$	(1,192,381	)	$	(4.36	)
Adjustments shown above (3)	32,803			0.12			(56,683		)	(0.20		)	55,138			0.20			184,566			0.66			1,138,576			4.16
Dilution attributable to equity-based payments (4)	—			—			—			—			—			—			—			—			—			—
Adjusted net loss (5)	$	(1,896	)	$	—		$	(5,747	)	$	(0.02	)	$	(10,457	)	$	(0.04	)	$	(40,692	)	$	(0.15	)	$	(53,805	)	$	(0.20	)

Common share and equivalents used for earnings (loss) per share:
Weighted average common shares outstanding	280,119						279,873						277,995						279,287						273,621
Dilutive stock options	—						—						—						—						—
Dilutive restricted shares and restricted share units	—						—						—						—						—
Dilutive warrants	—						—						—						—						—
Shares used to compute diluted loss per share for adjusted net loss	280,119						279,873						277,995						279,287						273,621


(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. All periods for which Adjusted net loss is presented include severance costs. Adjusted net loss is a useful metric in evaluating the Company's performance and facilitating comparisons with its peer companies, many of which use similar non-GAAP financial measures to supplement results under GAAP. Adjusted net loss may not be comparable to other similarly titled measures reported by other companies.

Certain non-GAAP financial measures (as defined below) 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

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 that can differ significantly among comparable companies. The Standardized Measure, a measure recognized under GAAP, as of December 31, 2016 was $311 million. The Standardized Measure represents the SEC PV-10 after giving effect to income taxes, and is calculated in accordance with the FASB ASC 932, Extractive Activities, Oil and Gas. EXCO's tax basis in the associated properties exceeded the pre-tax cash inflows and, as a result, there is no difference in Standardized Measure and SEC PV-10.

The NYMEX PV-10 as disclosed in this release differs from the Standardized Measure due to the oil and natural gas prices utilized in the determination of future net cash flows and other factors including, but not limited to, regional differentials. In addition, it includes the value of the potential reserves that, at December 31, 2016, were recorded as unproved due to the uncertainty regarding the availability of capital required to develop these reserves. These additional reserves meet the technical definition of proved reserves in accordance with certain professional societies, including the Society of Petroleum Engineers. These reserves will be reported as proved undeveloped reserves when the Company determines it has the financial capability to execute a development plan. EXCO believes that NYMEX PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows based on the current commodity price environment. The following table reconciles NYMEX PV-10 to the Standardized Measure as of December 31, 2016:



(in millions)	December 31, 2016
NYMEX PV-10, non-GAAP measure	$	970
Technical Proved Undeveloped Reserves	(393		)
Change in pricing assumptions from NYMEX^(*)to SEC and other	(266		)
Standardized Measure	$	311

(*)

Adjusted general and administrative expenses

The Company believes this non-GAAP measure is used by investors, analysts and management for valuations, peer comparisons and other recommendations. The exclusion of equity-based compensation is important to users that are evaluating the impact of the Company's cash-based general and administrative costs on its credit metrics and ability to service its indebtedness. In addition, the exclusion of cash-based costs such as restructuring and severance assists in the comparability between periods and similar measures are used in debt covenant calculations required under certain of the Company's debt agreements. Restructuring costs include legal and advisory costs incurred in connection with the Company's strategic initiative focused on restructuring its balance sheet and gathering and transportation contracts, and severance costs relate primarily to the Company's reductions in workforce.



	Three Months Ended									Year Ended
(in thousands)	December 31, 2016			September 30, 2016			December 31, 2015			December 31, 2016			December 31, 2015
General and administrative, GAAP	$	10,074		$	10,746		$	17,591		$	48,700		$	58,818
Less: Equity-based compensation	(220		)	(1,417		)	(3,153		)	(14,778		)	(7,198		)
Less: Restructuring and severance costs	(3,936		)	(2,697		)	(2,711		)	(5,645		)	(5,283		)
Adjusted general and administrative, non-GAAP measure	$	5,918		$	6,632		$	11,727		$	28,277		$	46,337

Important Information for Investors and Shareholders

This press release does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval.

The requisite shareholder approval matters are expected to be submitted to the shareholders of the Company for their consideration pursuant to a Definitive Proxy Statement on Schedule 14A (the “Proxy Statement”) that will be filed by the Company with the SEC and mailed to the Company’s shareholders. INVESTORS AND SECURITY HOLDERS OF THE COMPANY ARE URGED TO READ THE PROXY STATEMENT AND OTHER RELEVANT DOCUMENTS RELATED TO THE TRANSACTIONS DESCRIBED HEREIN THAT ARE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY AS THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE REQUISITE SHAREHOLDER APPROVAL MATTERS. Investors and shareholders will be able to obtain free copies of the Proxy Statement and other documents containing important information about the Company, once such documents are filed with the SEC, through the website maintained by the SEC at www.sec.gov. The Company will make available free of charge at www.excoresources.com (in the “Investor Relations” section), copies of materials it files with, or furnishes to, the SEC, or investors and shareholders may contact the Company at (214) 368-2084 to receive copies of documents that it files with or furnishes to the SEC.

Participants in the Proxy Solicitation

The Company and certain of its respective directors and officers may be deemed to be participants in the solicitation of proxies from the shareholders of the Company in connection with the requisite shareholder approval matters. Information about the directors and officers of the Company is set forth in its Definitive Proxy Statement on Schedule 14A for its 2016 annual meeting of shareholders, which was filed with the SEC on April 6, 2016, as well as its Current Reports on Form 8-K filed with the SEC on April 7, 2016, May 24, 2016, August 22, 2016, October 25, 2016, February 2, 2017 and March 3, 2017. These documents can be obtained free of charge from the sources indicated above. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the Proxy Statement and other relevant materials to be filed with the SEC when they become available.

Attachment

Statements

Consolidated Balance Sheets

EXCO Resources, Inc.