EXCO Resources, Inc. (NYSE: XCO) ("EXCO" or the "Company") today announced operating and financial results for the second quarter 2015.

2015 Second Quarter Highlights
  • Drilled 9 gross (4.4 net) and turned-to-sales 22 gross (5.7 net) operated horizontal wells in the second quarter 2015, consistent with the capital budget.
  • Produced 361 Mmcfe per day, or 33 Bcfe, for the second quarter 2015, which exceeded the midpoint of guidance. Production increased 22 Mmcfe per day from the first quarter 2015.
  • Adjusted EBITDA, a non-GAAP measure, was $69 million for the second quarter 2015, 19% above adjusted EBITDA for the first quarter 2015, primarily due to higher production as well as lower operating and general and administrative costs.
  • Cost saving initiatives resulted in general and administrative costs and gathering and transportation costs that were 7% and 6%, respectively, below the low-end of guidance, as well as operating costs within guidance. Reduced drilling and completion costs through negotiations with key vendors.
  • Enhanced completion design in East Texas Shelby area yielded strong results as evidenced by a 15% increase in estimated ultimate recoveries ("EUR") for undeveloped Haynesville shale locations to 1.5 Bcf per 1,000 lateral feet. The Company believes further upside is achievable based on certain of its proved developed producing wells in this area with EURs of 1.75 Bcf per 1,000 lateral feet.
  • Adjusted net income (loss), a non-GAAP measure, was a net loss of $12 million, or $0.05 per diluted share, and GAAP net income (loss) was a net loss of $454 million, or $1.67 per diluted share, for the second quarter 2015. The GAAP net loss was primarily due to the $394 million impairment of the Company's oil and natural gas properties pursuant to the ceiling test in accordance with full cost accounting.
  • Pro forma liquidity was $368 million as of the end of the second quarter 2015, after giving effect to the amendment to the Company's credit agreement that is anticipated to close this week. EXCO is evaluating transactions that would enhance its liquidity and provide additional financial flexibility.

Key Developments

Strategic plan update

EXCO recently implemented a transformational strategy that focuses on six core areas: 1) liability management, 2) operational performance, 3) capital deployment, 4) risk management, 5) portfolio repositioning, and 6) performance management. The Company believes the execution of this strategy will create long-term value for its shareholders. The six core areas and the Company's recent progress are detailed below:
  1. Liability management - The Company is focused on improving its capital structure and providing structural liquidity. The Company is currently evaluating transactions that would further enhance its liquidity and provide additional financial flexibility. This may include, but is not limited to, plans to refinance its existing indebtedness, incur additional indebtedness, issue equity or divest assets. EXCO expects to close this week on an amendment to its credit agreement that will facilitate these plans and had pro forma liquidity of $368 million if the amendment would have occurred at the end of the second quarter 2015.
  2. Operational performance - The Company's operational team is dedicated to the continuous improvement and innovation of well designs in order to maximize the return on capital. During the second quarter 2015, EXCO's well performance in the East Texas Shelby area resulted in a 15% increase in EURs for undeveloped Haynesville shale wells to 1.5 Bcf per 1,000 lateral feet. The Company continued to achieve strong results in the Buda formation during the second quarter 2015. EXCO demonstrated fiscal discipline during the second quarter 2015, as evidenced by gathering and transportation and general and administrative costs below the low-end of guidance and operating costs within guidance.
  3. Capital deployment - EXCO has implemented a disciplined capital allocation approach to ensure the highest and best use of capital. The Company will deploy its capital to each incremental well based on prices, cost and performance and will make real-time decisions to modify its development plans based on returns. As a result of the Company's ability to generate higher returns due to recent improvements to drilling and completion performance and cost reductions, EXCO is currently evaluating potential increases to its development plans.
  4. Risk management - EXCO utilizes derivative financial instruments to protect returns on the capital deployed and provide additional downside protection on its current base production. The Company plans to significantly increase the percentage of production volumes and time frame covered by derivative financial instruments. The strategy is designed to hedge proved developed production for a period of time that protects 85% of the value associated with new wells as they are brought on-line.
  5. Portfolio repositioning - The Company is focused on allocating capital to drilling to generate value and increasing its drilling inventory through leasing and acreage acquisitions. In May 2015, the Company's board of directors approved a $25 million increase to its 2015 capital budget to pursue certain oil and natural gas leasing opportunities in EXCO's core operating areas of East Texas and South Texas. During the second quarter 2015, the Company leased an additional 11,000 net acres in Zavala County, Texas.
  6. Performance management - The Company plans to rigorously manage to high performance levels to ensure high productivity. The Company is performing an analysis to benchmark its performance against its peer group and identify further areas for improvement.

Services and investment agreement

In April 2015, Bluescape Resources Company LLC ("Bluescape") deposited $10 million in escrow to be paid to EXCO upon acquisition of 5,882,353 common shares from EXCO, par value $0.001 per share, at a price per share of $1.70, pursuant to the services and investment agreement. The acquisition of the shares will occur upon the effectiveness of a resale registration statement. In addition, Bluescape will be obligated to purchase at least $40 million of additional common shares through open market purchases during the one year following the closing such that Bluescape will own common shares of EXCO with an aggregate cost basis of at least $50 million as of the first anniversary of the closing date, subject to certain extensions and exceptions. The shareholder approval required to close the services and investment agreement will be voted on during EXCO's annual meeting on August 5, 2015. At the closing, C. John Wilder, Executive Chairman of Bluescape, will become Executive Chairman of EXCO's Board of Directors.

Operational Results

         
Table 1: Summary of operating activities and operational results
Historical vs. guidance; mixed measures
 
Quarter-to-Date Year-to-Date Q2 Fiscal
6/30/15   3/31/15   6/30/14 6/30/15   6/30/14 2015 2015
Factors Unit Actual Actual   %   Actual   %   Actual Actual   %   Guidance Guidance
Rig counts (1) # 4 4   9 (56 ) 4 9 (56 ) N/A 4
 
Net wells drilled (1)
North Louisiana # 1.7 (100 ) 3.9 (100 ) 1.7 8.0

(79

)
N/A 1.7
East Texas # 2.9 2.0 45   1.9 53   4.9 3.8 29   N/A 9.3
South Texas # 1.5 1.8 (17 ) 4.1 (63 ) 3.3 8.8 (63 ) N/A 11.3
Appalachia and other #       N/A 0.3
Total net wells drilled # 4.4 5.5 (20 ) 9.9 (56 ) 9.9 20.6 (52 ) N/A 22.6
 
Net wells turned-to-sales (1)
North Louisiana # 1.4 10.5 (87 ) 4.0 (65 ) 11.9 4.7 153   N/A 11.9
East Texas # 1.0 100   1.0   1.0 1.0   N/A 5.9
South Texas # 3.3 4.1 (20 ) 2.9 14   7.4 5.3 40   N/A 14.8
Appalachia and other #       N/A 0.5
Total net wells turned-to-sales # 5.7 14.6 (61 ) 7.9 (28 ) 20.3 11.0 85   N/A 33.1
 
Daily production
North Louisiana Mmcfe/d 231 207 12   235 (2 ) 219 247 (11 ) N/A N/A
East Texas Mmcfe/d 40 45 (11 ) 22 82   43 22 95   N/A N/A
South Texas Mmcfe/d 43 36 19   39 10   39 39   N/A N/A
Appalachia and other (2) Mmcfe/d 47 51 (8 ) 87 (46 ) 49 87 (44 ) N/A N/A
Total daily production Mmcfe/d 361 339 6   383 (6 ) 350 395 (11 ) 355-365 335-355
 
Production
Oil Mbbls 594 504 18   579 3   1,098 1,172 (6 ) 550-570 2,250-2,300
Natural gas Bcf 29.3 27.5 7   31.4 (7 ) 56.8 64.5 (12 ) 29.0-29.8 108.8-115.8
Total production Bcfe 32.9 30.5 8   34.9 (6 ) 63.4 71.5 (11 ) 32.3-33.2 122.3-129.6
 
Capital Expenditures   $MM   75   103   (27 )   99   (24 )   178   199   (11 )   N/A   295-305
(1)   Includes rigs and wells operated by EXCO and excludes rigs and wells operated by others.
(2) Includes 25 Mmcfe/d of production from Compass Production Partners, LP ("Compass") for both the three and six months ended June 30, 2014, respectively. EXCO sold its interest in Compass on October 31, 2014.
 

North Louisiana

Highlights:
  • Produced 231 Mmcfe per day, an increase of 24 Mmcfe per day, or 12%, from the first quarter 2015 and a decrease of 4 Mmcfe per day, or 2%, from the second quarter 2014.
  • Turned-to-sales 4 gross (1.4 net) Haynesville shale wells in Caddo Parish.

EXCO's increase in production compared to the first quarter 2015 was primarily the result of the timing of completion activities. The Company entered 2015 with three operated rigs drilling in this region and subsequently moved these rigs to the Shelby area of East Texas. EXCO does not have plans for further development in this region during the remainder of 2015. EXCO is analyzing data and assessing potential modifications to its Haynesville shale well design in this region, which includes enhanced completion methods that have proven to be successful in its East Texas region, including the use of more proppant, modified well spacing and longer laterals. These initiatives have the potential to increase the rates of return (*) in the Holly area by approximately 20%.

The Company continues to monitor and analyze the results from its re-frac stimulation tests and remains optimistic about the potential. EXCO plans to resume its re-frac program in 2016.

East Texas

Highlights:
  • Produced 40 Mmcfe per day, a decrease of 5 Mmcfe per day, or 11%, from the first quarter 2015 and an increase of 18 Mmcfe per day, or 82%, from the second quarter 2014.
  • Drilled 6 gross (2.9 net) operated horizontal Haynesville and Bossier wells in the Shelby area and turned-to-sales 2.0 gross (1.0 net) wells in the Haynesville and Bossier shales in the Shelby area.

EXCO's decrease in production compared to the first quarter 2015 was primarily the result of normal production declines in excess of the production from the wells turned-to-sales during the quarter and higher downtime. The Company's 2015 drilling program in this region is designed to result in a higher percentage of the overall number of wells turned-to-sales later in the year. The higher downtime was due to various factors including drilling and completion activities, workovers and flooding.

The enhanced completion methods in this region continue to yield strong results as evidenced in the performance from wells included in EXCO's 2014 and 2015 drilling programs. The improved well performance in this region resulted in an increase in the EUR to 1.5 Bcf per 1,000 lateral feet for certain undeveloped Haynesville shale locations compared to 1.3 Bcf per 1,000 lateral feet as of year-end 2014. The increase in the EUR was reviewed by a third-party reserve engineer. EXCO continues to refine its completion techniques in this region, which will include up to 2,700 lbs of proppant per foot in certain wells to be drilled during the remainder of 2015, compared to an average of 1,400 lbs of proppant per foot in the Company's 2014 drilling program. The estimated cost for the Haynesville shale wells included in the Company's plans for the remainder of the year is $10.3 million per well based on an average lateral length of 6,900 feet and 2,700 lbs of proppant per foot.

The East Texas region is the primary focus of EXCO's 2015 development program, which includes an average of 3 rigs for the remainder of 2015. This will allow the Company to drill 11 gross (4.4 net) operated horizontal wells and turn 10 gross (4.9 net) wells to sales during the remainder of 2015. EXCO is targeting a rate of return (*) of approximately 30% to 35% for the East Texas Shelby wells included in its 2015 drilling program.

South Texas

Highlights:
  • Produced 7.2 Mboe per day, an increase of 1.2 Mboe per day, or 19%, from the first quarter 2015 and an increase of 0.7 Mboe per day, or 10%, from the second quarter 2014.
  • Drilled 3 gross (1.5 net) operated horizontal wells and turned-to-sales 16 gross (3.3 net) operated horizontal wells.

EXCO's increase in production compared to the first quarter 2015 was primarily due to the timing of completion activities and lower downtime. The wells turned-to-sales during the year-to-date 2015 were concentrated late in the first quarter 2015 and early in the second quarter 2015. The decrease in downtime was due to construction and maintenance of central production and storage facilities and offset frac activities that occurred during the first quarter 2015 and partially offset by flooding in the second quarter 2015. Development included 2 gross (0.8 net) wells drilled and 15 gross (2.7 net) wells turned-to-sales in the Eagle Ford shale. The wells turned-to-sales in the Eagle Ford shale averaged initial production rates of 672 Bbls per day. EXCO continues to reduce its drilling times and is currently averaging 10 days to drill an average total measured depth of 14,200 feet. Also, the Company has been able to extend the lateral length up to 9,500 feet on recent wells. As a result of the Company's development activities, its core area of 11,300 net acres in Zavala County, Texas is entirely held-by-production. The Company's plans for the remainder of the year include drilling 3 gross (1.3 net) wells and turning-to-sales 4 gross (1.6 net) wells. The estimated cost for the wells included in the Company's plans for the remainder of the year is $6.5 million per well based on an average lateral length of 8,500 feet.

Development included 1 gross (0.7 net) Buda well which was drilled and turned-to-sales. This was the Company's second operated Buda well and the maximum 24-hour production rate was 520 Bbls of oil. The Company's first operated Buda well had cumulative production of 60 Mbbls in its first five months of production. The relatively low costs of drilling the Buda provide an attractive near-term development opportunity, even in a low commodity price environment. Therefore, the Company's plans for the remainder of 2015 include drilling 7 gross (6.6 net) and turning-to-sales 6 gross (5.8 net) wells in the Buda formation. The additional wells included in EXCO's plans for the remainder of 2015 are expected to cost $2.9 million per well based on an average lateral length of 10,500 feet. EXCO is targeting a rate of return (*) of approximately 40% to 50% for the Buda wells included in its 2015 drilling program.

Based on the recent success of nearby results, the Company leased an additional 11,000 net acres in Zavala County, Texas. The Company did not acquire any interests in wells under its participation agreement with a joint venture partner in the Eagle Ford shale during the second quarter 2015 due to low commodity prices. EXCO's current strategy is to allocate its capital to development opportunities with higher rates of return compared to the acquisition of producing properties.

Appalachia

Highlights:
  • Produced 47 Mmcfe per day, a decrease of 4 Mmcfe per day, or 8%, from the first quarter 2015 and a decrease of 14 Mmcfe per day, or 23%, from the second quarter 2014.

EXCO's decrease in production from the first quarter 2015 was primarily the result of normal production declines and higher downtime due to a third-party pipeline disruption in Northeast Pennsylvania. The pipeline disruption resulted in approximately 300 Mmcf of production volumes being shut-in while the pipeline was repaired. EXCO's plans for the remainder of 2015 include drilling 1 gross (0.3 net) operated horizontal well in the Marcellus shale and turning-to-sales 1 gross (0.5 net) well that is awaiting gathering lines that are currently being constructed. The Company's position in the Marcellus shale requires low maintenance capital and approximately 80% of the acreage is held-by-production, which provides flexibility in the timing of the development of this region.
(*)   Rates of return are based on NYMEX futures prices as of June 30, 2015, including natural gas prices per Mmbtu of $2.93 for 2015, $3.17 for 2016, $3.36 for 2017, $3.44 for 2018, $3.51 for 2019, $3.61 for 2020 and $4.00 thereafter, and oil prices per Bbl of $60.30 for 2015, $62.08 for 2016, $63.62 for 2017, $65.18 for 2018, $66.42 for 2019, $67.44 for 2020 and $70.00 thereafter.
 

Financial Results
         
Table 2: Summary of operational earnings
Historical vs. guidance; mixed measures
 
Quarter-to-Date Year-to-Date Q2 Fiscal
6/30/15   3/31/15   6/30/14 6/30/15   6/30/14 2015 2015
Factors Unit Actual Actual   % Actual   % Actual Actual   % Guidance Guidance
Operating revenues
Oil revenues $MM 32   21   52   56   (43 ) 52   108   (52 ) N/A N/A
Natural gas revenues $MM 62   65   (5 ) 127   (51 ) 128   273   (53 ) N/A N/A
Total revenues $MM 94   86   9   183   (49 ) 180   381   (53 ) N/A N/A
Realized oil prices $/Bbl 53.11   41.43   28   96.81   (45 ) 47.75   92.48   (48 ) N/A N/A
Oil price differentials $/Bbl (4.65 ) (6.96 ) (33 ) (6.33 )

(27

)
(5.71 ) (8.26 )

(31

)
(4.00-6.00) (4.00-6.00)
Realized gas prices $/Mcf 2.12   2.38   (11 ) 4.04   (48 ) 2.25   4.24   (47 ) N/A N/A
Gas price differentials $/Mcf (0.52 ) (0.60 ) (13 ) (0.64 )

(19

)
(0.56 ) (0.55 )

2

 
(0.50-0.60) (0.50-0.60)
 
Derivative financial instruments
Cash settlements (payments) $MM 29   28   4   (15 ) 293   57   (34 ) 268   N/A N/A
Cash settlements (payments) $/Mcfe 0.89   0.91   (2 ) (0.42 ) 312   0.90   (0.48 ) 288   N/A N/A
 
Costs and expenses
Oil and natural gas operating costs $MM 14   15   (7 ) 16   (13 ) 29   35   (17 ) N/A N/A
Production and ad valorem taxes $MM 6   5   20   7   (14 ) 10   15   (33 ) N/A N/A
Gathering and transportation $MM 25   26   (4 ) 26   (4 ) 51   51     N/A N/A
Oil and natural gas operating costs $/Mcfe 0.43   0.49   (12 ) 0.45   (4 ) 0.46   0.48   (4 ) 0.40-0.45 0.40-0.45
Production and ad valorem taxes $/Mcfe 0.17   0.16   6   0.21   (19 ) 0.17   0.21   (19 ) 0.15-0.20 0.15-0.20
Gathering and transportation $/Mcfe 0.75   0.84   (11 ) 0.75     0.80   0.71   13   0.80-0.85 0.80-0.85
General and administrative (1) $MM 11   14   (21 ) 18   (39 ) 25   34   (26 ) 12-14 48-53
 
Operational earnings
Adjusted EBITDA (2) $MM 69   58   19   105   (34 ) 127   217   (41 ) N/A N/A
GAAP net income (loss) $MM (454 ) (318 ) (43 ) 2   N/M   (772 ) (2 ) N/M   N/A N/A
Adjusted net income (loss) (2) $MM (12 ) (19 ) 37   7   (271 ) (31 ) 19   (263 ) N/A N/A
GAAP diluted shares outstanding MM 272   272     271     272   266   2   N/A N/A
Adjusted diluted shares outstanding MM 272   272     271     272   266   2   N/A N/A
GAAP diluted EPS $/Share (1.67 ) (1.17 ) (43 ) 0.01   N/M   (2.84 ) (0.01 ) N/M   N/A N/A
Adjusted diluted EPS   $/Share   (0.05 )   (0.07 )   29     0.03     (267 )   (0.11 )   0.07     (257 )   N/A   N/A
(1)   Excludes share-based compensation expenses of $1.4 million, $1.7 million and $1.7 million for the three months ended June 30, 2015, March 31, 2015 and June 30, 2014, respectively, and $3.1 million and $3.3 million for the six months ended June 30, 2015 and 2014, respectively.
(2) Adjusted EBITDA and Adjusted net income (loss) are non-GAAP measures. See Financial Data section for definitions and reconciliations.
 

EXCO's increase in adjusted EBITDA compared to the first quarter 2015 was due primarily to higher production and lower operating and general and administrative costs. Additionally, gathering and transportation costs were lower due to a renegotiated firm transportation contract in the North Louisiana region. The GAAP net loss during both the first and second quarters 2015 was primarily due to the impairment of the Company's oil and natural gas properties pursuant to the ceiling test in accordance with full cost accounting.

EXCO executed on its commitment to fiscal discipline during the second quarter 2015, as evidenced by gathering and transportation and general and administrative costs below the low-end of guidance and operating costs within guidance. EXCO has implemented several initiatives to reduce its general and administrative costs, including reductions in its workforce during the second quarter 2014 and first quarter 2015. Excluding the impact of the severance costs, general and administrative expenses decreased 30% for the year-to-date 2015 compared to the same period in 2014 (excluding share-based compensation expenses).

Cash Flow Results
         
Table 3: Summary of key cash flow items
Historical vs. guidance; mixed measures
 
Quarter-to-Date Year-to-Date Q2 Fiscal
6/30/15   3/31/15   6/30/14 6/30/15   6/30/14 2015 2015

Factors
Unit Actual Actual   % Actual   % Actual Actual   % Guidance Guidance
Cash flow provided by (used in)
Operating activities $MM 52   57   (9 ) 68   (24 ) 108   268   (60 ) N/A N/A
Investing activities $MM (72 ) (120 ) 40   (101 ) 29   (193 ) (125 ) (54 ) N/A N/A
Financing activities $MM 45   43   5   (15 ) 400   88   (148 ) 159   N/A N/A
Net increase (decrease) in cash $MM 24   (21 ) 214   (49 ) 149   4   (5 ) 180   N/A N/A
 
Other key cash flow items
Adjusted operating cash flow (1) $MM 45   36   25   84   (46 ) 81   178   (54 ) N/A N/A
Free cash flow (1)   $MM   (32 )   (64 )   50     (28 )   (14 )   (96 )   71     (235 )   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.
 

During the second quarter 2015, EXCO primarily used its cash flows from operations and borrowings under the EXCO Resources Credit Agreement to fund drilling and development. The decrease in cash used in investing activities in the second quarter 2015 compared to the first quarter 2015 was primarily due to decreased development activities in the current year compared to the prior year. The cash used in investing activities during the first quarter 2015 included a significant amount of payments related to expenditures incurred on wells drilled and completed in 2014.

Liquidity Results

         
Table 4: Financial flexibility measures
Historical vs. guidance; mixed measures
 
Quarter-to-Date Year-to-Date Q2 Fiscal
6/30/15   3/31/15   6/30/14 6/30/15   6/30/14 2015 2015
Factors Unit Actual Actual   % Actual   % Actual Actual   % Guidance Guidance
Cash (1) $MM 67 48 40 53 26   67 53 26   N/A N/A
Gross debt (2) $MM 1,542 1,497 3 1,432 8   1,542 1,432 8   N/A N/A
Net debt $MM 1,475 1,450 2 1,379 7   1,475 1,379 7   N/A N/A
Adjusted EBITDA (3) $MM 69 58 19 105 (34 ) 127 217 (41 ) N/A N/A
Cash interest expenses (4) $MM 27 26 4 28 (4 ) 53 50 6   N/A N/A
Adjusted EBITDA/Interest (5) x 2.56 2.23 15 3.75 (32 ) 2.40 4.34 (45 ) N/A N/A
Secured debt/LTM Adjusted EBITDA (5) x 0.97 0.73 33 0.41 137   0.97 0.41 137   N/A N/A
Net debt/LTM Adjusted EBITDA   x   4.90   4.30   14   3.07   60     4.90   3.07   60     N/A   N/A
(1)   Includes restricted cash of $18 million, $22 million and $15 million as of June 30, 2015, March 31, 2015 and June 30, 2014, respectively.
(2) Excludes unamortized discount of $5 million, $6 million and $7 million as of June 30, 2015, March 31, 2015 and June 30, 2014, respectively.
(3) Adjusted EBITDA is a non-GAAP measure. See Financial Data section for definition and reconciliation.
(4) Cash interest expenses exclude the amortization of debt issuance costs, discount on notes and capitalized interest.
(5) These ratios differ in certain respects from the calculations of comparable measures in the EXCO Resources Credit Agreement. As of June 30, 2015, the ratio of consolidated EBITDAX to consolidated interest expense (as defined in the agreement) was 2.8 to 1.0 and the ratio of secured indebtedness to consolidated EBITDAX (as defined in the agreement) was 1.0 to 1.0.
         
Table 5: Liquidity schedule
Historical vs. guidance; mixed measures
 
Quarter-to-Date Year-to-Date Q2 Fiscal
6/30/15   3/31/15   6/30/14 6/30/15   6/30/14 2015 2015
Factors Unit Actual Actual   % Actual   % Actual Actual   % Guidance Guidance
Borrowing base on revolver $MM 725 725   875 (17 ) 725 875 (17 ) N/A N/A
Amount drawn on revolver $MM 292 247 18   182 60   292 182 60   N/A N/A
Letters of credit $MM 7 7   7   7 7   N/A N/A
Available for borrowing $MM 426 471 (10 ) 686 (38 ) 426 686 (38 ) N/A N/A
Cash (1) $MM 67 48 40   53 26   67 53 26   N/A N/A
Liquidity (2)   $MM   493   518   (5 )   739   (33 )   493   739   (33 )   N/A   N/A
(1)   Includes restricted cash of $18 million, $22 million and $15 million as of June 30, 2015, March 31, 2015 and June 30, 2014, respectively.
(2)

Liquidity is calculated as the unused borrowing base under the EXCO Resources Credit Agreement plus cash. The Company expects to close this week on an amendment to the EXCO Resources Credit Agreement, which will decrease its borrowing base to $600 million. On a pro forma basis, EXCO's liquidity would have been $368 million if this amendment had occurred on June 30, 2015.
 

EXCO Resources Credit Agreement Amendment

The Company expects to close this week on an amendment to its credit agreement ("EXCO Resources Credit Agreement"), which will decrease the borrowing base to $600 million in connection with the semi-annual borrowing base redetermination. The next scheduled borrowing base redetermination for the EXCO Resources Credit Agreement will occur in the first quarter of 2016. The amendment also contains modifications to the borrowing base, interest rate grid and financial covenants in the event of incurrence of certain indebtedness subordinated to the EXCO Resources Credit Agreement.

Risk Management Results

       
Table 6: Hedging position as of June 30, 2015

2Q 15; mixed measures
 
Six Months Ended Twelve Months Ended Twelve Months Ended
12/31/15 12/31/16 12/31/17
Factors Unit Volume   Strike Price Volume   Strike Price Volume   Strike Price
Natural gas
Fixed price swaps - Henry Hub Bbtu/$/Mmbtu 25,300 4.02 16,470 3.30 7,300 3.42
Three-way collars - Henry Hub Bbtu 13,800   10,980    
Sold call options $/Mmbtu   4.47   4.80  
Purchased put options $/Mmbtu   3.83   3.90  
Sold put options $/Mmbtu   3.33   3.40  
Sold call options - Henry Hub Bbtu/$/Mmbtu 10,120 4.29
 
Oil
Fixed price swaps - WTI Mbbl/$/Bbl 506 84.18 732 64.82
Fixed price swaps - LLS Mbbl/$/Bbl 138 94.75
Fixed price basis swaps Mbbl/$/Bbl 46 6.10
Sold call options - WTI   Mbbl/$/Bbl   184   100.00        
 

As of June 30, 2015, approximately 68% of the 2015 forecasted natural gas production and 55% of the 2015 forecasted oil production has been hedged. The Company plans to increase the percentage of forecasted volumes and time frame covered by oil and natural gas derivative contracts in order to protect its returns on capital deployed and provide additional downside protection on its current base production.

Financial Data

The following financial statements are attached.
Attachment   Statements   Company   Period
1 Condensed Consolidated Balance Sheets EXCO Resources, Inc. 6/30/2015
2 Condensed Consolidated Statements Of Operations EXCO Resources, Inc. 6/30/2015
3 Condensed Consolidated Statements Of Cash Flows EXCO Resources, Inc. 6/30/2015
4 EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations EXCO Resources, Inc. 6/30/2015
5   GAAP Net Income (Loss) and Adjusted Net Income (Loss) Reconciliations   EXCO Resources, Inc.   6/30/2015
 

EXCO will host a conference call on Monday, July 27, 2015 at 9:00 a.m. (Central time) to discuss the contents of this release and respond to questions. Please call (800) 309-5788 if you wish to participate, and ask for the EXCO conference call ID#24918639. 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 August 12, 2015. Please call (800) 585-8367 and enter conference ID#24918639 to hear the recording. A digital recording of the conference call will also be available on EXCO's website.

Additional information about EXCO Resources, Inc. may be obtained by contacting Chris Peracchi, EXCO's Vice President of Finance and Investor Relations, and Treasurer, at EXCO's headquarters, 12377 Merit Drive, Suite 1700, Dallas, TX 75251, telephone number (214) 368-2084, or by visiting EXCO's website at www.excoresources.com. EXCO's SEC filings and press releases can be found under the Investor Relations tab.

This press release contains statements that are forward-looking statements as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, among others, statements regarding estimates, expectations and production forecasts for 2015, estimates of costs and expenses for 2015, EXCO's drilling program, and the closing of the transactions under the services and investment agreement. It is important to communicate expectations of future performance to investors. However, events may occur in the future that EXCO is unable to accurately predict, or over which EXCO has no control. Users of the financial statements are cautioned not to place undue reliance on a forward-looking statement. Any number of factors could cause actual results to differ materially from those in EXCO's forward-looking statements, including, but not limited to, the volatility of oil and natural gas prices, future capital requirements and the availability of capital and financing, uncertainties about reserve estimates, the outcome of future drilling activity, environmental risks and regulatory changes. Declines in oil or natural gas prices may have a material adverse effect on EXCO's financial condition, liquidity, results of operations, ability to fund operations and the amount of oil or natural gas that can be produced economically. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. EXCO undertakes no obligation to publicly update or revise any forward-looking statements. When considering EXCO's forward-looking statements, investors are urged to read the cautionary statements and the risk factors included in EXCO's Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission ("SEC") on February 25, 2015, as amended by Amendment No. 1 to Annual Report on Form 10-K/A filed with the SEC on April 10, 2015 and its other periodic filings with the SEC.
     
 
Attachment Statements Company Period
1   Condensed Consolidated Balance Sheets   EXCO Resources, Inc.   6/30/2015
   
(in thousands) June 30, 2015 December 31, 2014
(Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 49,907 $ 46,305
Restricted cash 17,581 23,970
Accounts receivable, net:
Oil and natural gas 55,479 81,720
Joint interest 40,231 65,398
Other 8,164 8,945
Derivative financial instruments 55,111 97,278
Inventory and other   7,859     7,150  
Total current assets   234,332     330,766  
Equity investments 55,188 55,985
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized 248,196 276,025
Proved developed and undeveloped oil and natural gas properties 3,385,948 3,852,073
Accumulated depletion   (2,537,476 )   (2,414,461 )
Oil and natural gas properties, net   1,096,668     1,713,637  
Other property and equipment, net 23,937 24,644
Deferred financing costs, net 26,385 30,636
Derivative financial instruments 3,772 2,138
Deferred income taxes 18,669 35,935
Goodwill   163,155     163,155  
Total assets $ 1,622,106   $ 2,356,896  
Liabilities and shareholders' equity
Current liabilities:
Accounts payable and accrued liabilities $ 93,721 $ 110,211
Revenues and royalties payable 135,180 152,651
Drilling advances 30,077 37,648
Accrued interest payable 26,046 26,265
Current portion of asset retirement obligations 1,769 1,769
Income taxes payable
Deferred income taxes 18,669 35,935
Derivative financial instruments   320     892  
Total current liabilities   305,782     365,371  
Long-term debt 1,537,243 1,446,535
Asset retirement obligations 36,502 34,986
Commitments and contingencies
Shareholders' equity:
Common shares, $0.001 par value; 350,000,000 authorized shares; 274,328,625 shares issued and 273,750,583 shares outstanding at June 30, 2015; 274,351,756 shares issued and 273,773,714 shares outstanding at December 31, 2014 270 270
Additional paid-in capital 3,507,050 3,502,209
Accumulated deficit (3,757,126 ) (2,984,860 )
Treasury shares, at cost; 578,042 shares at June 30, 2015 and December 31, 2014   (7,615 )   (7,615 )
Total shareholders' equity   (257,421 )   510,004  
Total liabilities and shareholders' equity $ 1,622,106   $ 2,356,896  
     
 
Attachment Statements Company Period
2   Condensed Consolidated Statements Of Operations (Unaudited)   EXCO Resources, Inc.   6/30/2015
   
Three Months Ended Six Months Ended
(in thousands, except per share data) June 30, 2015   March 31, 2015   June 30, 2014 June 30, 2015   June 30, 2014
Revenues:
Total revenues $ 93,742 $ 86,320 $ 182,966 $ 180,062 $ 381,438
Costs and expenses:
Oil and natural gas operating costs 14,135 14,941 15,827 29,076 34,614
Production and ad valorem taxes 5,603 4,861 7,364 10,464 14,973
Gathering and transportation 24,785 25,715 26,038 50,500 50,651
Depletion, depreciation and amortization 61,658 62,489 67,253 124,147 136,528
Impairment of oil and natural gas properties 394,327 276,327 670,654
Accretion of discount on asset retirement obligations 568 556 695 1,124 1,376
General and administrative 12,597 15,237 19,504 27,834 36,842
Other operating items   1,534     (188 )   2,973     1,346     5,719  
Total costs and expenses   515,207     399,938     139,654     915,145     280,703  
Operating income (loss) (421,465 ) (313,618 ) 43,312 (735,083 ) 100,735
Other income (expense):
Interest expense, net (25,571 ) (27,490 ) (25,968 ) (53,061 ) (46,132 )
Gain (loss) on derivative financial instruments (6,631 ) 23,710 (14,718 ) 17,079 (57,740 )
Other income 47 51 77 98 123
Equity income (loss)   (535 )   (765 )   (410 )   (1,300 )   701  
Total other income (expense)   (32,690 )   (4,494 )   (41,019 )   (37,184 )   (103,048 )
Income (loss) before income taxes (454,155 ) (318,112 ) 2,293 (772,267 ) (2,313 )
Income tax expense                    
Net income (loss) $ (454,155 ) $ (318,112 ) $ 2,293   $ (772,267 ) $ (2,313 )
Earnings (loss) per common share:
Basic:
Net income (loss) $ (1.67 ) $ (1.17 ) $ 0.01   $ (2.84 ) $ (0.01 )
Weighted average common shares outstanding   271,549     271,522     270,492     271,536     265,631  
Diluted:
Net income (loss) $ (1.67 ) $ (1.17 ) $ 0.01   $ (2.84 ) $ (0.01 )
Weighted average common shares and common share equivalents outstanding   271,549     271,522     271,226     271,536     265,631  
     
 
Attachment Statements Company Period
3   Condensed Consolidated Statements Of Cash Flows (Unaudited)   EXCO Resources, Inc.   6/30/2015
 
Six Months Ended June 30,
(in thousands) 2015   2014
Operating Activities:
Net loss $ (772,267 ) $ (2,313 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization 124,147 136,528
Share-based compensation expense 3,119 3,252
Accretion of discount on asset retirement obligations 1,124 1,376
Impairment of oil and natural gas properties 670,654
(Income) loss from equity method investments 1,300 (701 )
(Gain) loss on derivative financial instruments (17,079 ) 57,740
Cash receipts (payments) of derivative financial instruments 57,039 (34,469 )
Amortization of deferred financing costs and discount on debt issuance 6,975 7,697
Effect of changes in:
Restricted cash (600 )
Accounts receivable 50,758 30,796
Other current assets 790 (577 )
Accounts payable and other current liabilities   (17,756 )   68,793  
Net cash provided by operating activities   108,204     268,122  
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment (204,600 ) (197,341 )
Property acquisitions (7,608 ) (426 )
Proceeds from disposition of property and equipment 7,397 76,266
Restricted cash 6,989 5,349
Net changes in advances to joint ventures 5,756 (10,540 )
Equity method investments   (503 )   1,749  
Net cash used in investing activities   (192,569 )   (124,943 )
Financing Activities:
Borrowings under credit agreements 90,000
Repayments under credit agreements (882,424 )
Proceeds received from issuance of 2022 Notes 500,000
Proceeds (payments) for issuance of common shares, net (2 ) 271,772
Payments of common share dividends (15 ) (27,066 )
Deferred financing costs and other   (2,016 )   (10,066 )
Net cash provided by (used in) financing activities   87,967     (147,784 )
Net increase (decrease) in cash 3,602 (4,605 )
Cash at beginning of period   46,305     50,483  
Cash at end of period $ 49,907   $ 45,878  
Supplemental Cash Flow Information:
Cash interest payments $ 52,069 $ 39,576
Income tax payments
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation $ 1,936 $ 2,955
Capitalized interest 7,027 10,255
Issuance of common stock for director services 100 129
     
 
Attachment Statements Company Period
4   EBITDA, Adjusted EBITDA, Adjusted Operating Cash Flow and Free Cash Flow Reconciliations (Unaudited)   EXCO Resources, Inc.   6/30/2015
   
Three Months Ended Six Months Ended
(in thousands) June 30, 2015   March 31, 2015   June 30, 2014 June 30, 2015   June 30, 2014
Net income (loss) $ (454,155 ) $ (318,112 ) $ 2,293 $ (772,267 ) $ (2,313 )
Interest expense 25,571 27,490 25,968 53,061 46,132
Income tax expense
Depletion, depreciation and amortization   61,658     62,489     67,253     124,147     136,528  
EBITDA(1) $ (366,926 ) $ (228,133 ) $ 95,514 $ (595,059 ) $ 180,347
Accretion of discount on asset retirement obligations 568 556 695 1,124 1,376
Impairment of oil and natural gas properties 394,327 276,327 670,654
Other items impacting comparability 2,897 3,172 6,775 6,069 9,375
Equity (income) loss 535 765 410 1,300 (701 )
(Gain) loss on derivative financial instruments 6,631 (23,710 ) 14,718 (17,079 ) 57,740
Cash settlements (payments) on derivative financial instruments 29,401 27,638 (14,659 ) 57,039 (34,469 )

Share-based compensation expense
  1,439     1,680     1,745     3,119     3,252  
Adjusted EBITDA (1) $ 68,872 $ 58,295 $ 105,198 $ 127,167 $ 216,920
Interest expense (25,571 ) (27,490 ) (25,968 ) (53,061 ) (46,132 )
Income tax expense
Amortization of deferred financing costs and discount 2,099 4,876 5,253 6,975 7,697
Other operating items impacting comparability (2,897 ) (3,172 ) (6,775 ) (6,069 ) (9,375 )
Changes in working capital   9,171     (24,021 )   (9,920 )   33,192     99,012  
Net cash provided by operating activities $ 51,674   $ 56,530   $ 67,788   $ 108,204   $ 268,122  
 
Three Months Ended Six Months Ended
(in thousands) June 30, 2015 March 31, 2015 June 30, 2014 June 30, 2015 June 30, 2014
Cash flow from operations, GAAP $ 51,674 $ 56,530 $ 67,788 $ 108,204 $ 268,122
Net change in working capital (9,171 ) (24,021 ) 9,920 (33,192 ) (99,012 )
Other operating items impacting comparability   2,897     3,172     6,775     6,069     9,375  
Adjusted operating cash flow, non-GAAP measure (2) $ 45,400   $ 35,681   $ 84,483   $ 81,081   $ 178,485  
 
Three Months Ended Six Months Ended
(in thousands) June 30, 2015 March 31, 2015 June 30, 2014 June 30, 2015 June 30, 2014
Cash flow from operations, GAAP $ 51,674 $ 56,530 $ 67,788 $ 108,204 $ 268,122
Less: Additions to oil and natural gas properties, gathering assets and equipment   (83,712 )   (120,888 )   (95,937 )   (204,600 )   (197,341 )
Free cash flow, non-GAAP measure (3) $ (32,038 ) $ (64,358 ) $ (28,149 ) $ (96,396 ) $ 70,781  
 
(1) Earnings before interest, taxes, depreciation, depletion and amortization ("EBITDA") represents net income (loss) adjusted to exclude interest expense, income taxes and depreciation, depletion and amortization. "Adjusted EBITDA" represents EBITDA adjusted to exclude other operating items impacting comparability, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash impairments of assets, share-based compensation and income or losses from equity method investments. EXCO has presented EBITDA and Adjusted EBITDA because they are a widely used measure by investors, analysts and rating agencies for valuations, peer comparisons and investment recommendations. In addition, similar measures are used in covenant calculations required under the EXCO Resources Credit Agreement, the indenture governing EXCO's 7.5% senior notes due September 15, 2018 ("2018 Notes"), and the indenture governing EXCO's 8.5% senior notes due April 15, 2022 ("2022 Notes"). Compliance with the liquidity and debt incurrence covenants included in these agreements is considered material to the Company. EXCO's computations of EBITDA and Adjusted EBITDA may differ from computations of similarly titled measures of other companies due to differences in the inclusion or exclusion of items in the Company's computations as compared to those of others. EBITDA and Adjusted EBITDA are measures that are not prescribed by GAAP. EBITDA and Adjusted EBITDA specifically exclude changes in working capital, capital expenditures and other items that are set forth on a cash flow statement presentation of the Company's operating, investing and financing activities. As such, investors are encouraged not to use these measures as substitutes for the determination of net income, net cash provided by operating activities or other similar GAAP measures. The calculation of EBITDA and Adjusted EBITDA as presented herein differ in certain respects from the calculation of comparable measures in the EXCO Resources Credit Agreement, the indenture governing the 2018 Notes and the indenture governing the 2022 Notes.
 
(2) Adjusted operating cash flow is presented because the Company believes it is a useful financial indicator for companies in its industry. This non-GAAP disclosure is widely accepted as a measure of an oil and natural gas company's ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. Adjusted operating cash flow is not a measure of financial performance pursuant to GAAP and should not be used as an alternative to cash flows from operating, investing, or financing activities. Other operating items impacting comparability have been excluded as they do not reflect the Company's on-going operating activities.
 
(3) Free cash flow is cash provided by operating activities less capital expenditures. This non-GAAP measure is used predominantly as a forecasting tool to estimate cash available to fund indebtedness and other investments.
     
 
Attachment Statements Company Period
5   GAAP Net Income (Loss) and Adjusted Net Income (Loss) Reconciliations (Unaudited)   EXCO Resources, Inc.   6/30/2015
   
Three Months Ended Six Months Ended
June 30, 2015   March 31, 2015   June 30, 2014 June 30, 2015   June 30, 2014
(in thousands, except per share amounts) Amount  

Per share
Amount  

Per share
Amount  

Per share
Amount  

Per share
Amount  

Per share
Net income (loss), GAAP $ (454,155 ) $ (318,112 ) $ 2,293 $ (772,267 ) $ (2,313 )
Adjustments:
(Gain) loss on derivative financial instruments 6,631 (23,710 ) 14,718 (17,079 ) 57,740
Cash settlements (payments) on derivative financial instruments 29,401 27,638 (14,659 ) 57,039 (34,469 )
Impairment of oil and natural gas properties 394,327 276,327 670,654
Adjustments included in equity (income) loss 334 502 836 (1,749 )
Other items impacting comparability 2,897 3,172 6,775 6,069 9,375
Deferred finance cost amortization acceleration 2,764 3,099 2,764 3,471
Income taxes on above adjustments (1) (173,436 ) (114,677 ) (3,973 ) (288,113 ) (13,747 )
Adjustment to deferred tax asset valuation allowance (2)   181,662     127,245     (917 )   308,907     925  
Total adjustments, net of taxes   441,816     299,261     5,043     741,077     21,546  
Adjusted net income (loss) (5) $ (12,339 ) $ (18,851 ) $ 7,336   $ (31,190 ) $ 19,233  
 
Net income (loss), GAAP (3) $ (454,155 ) $ (1.67 ) $ (318,112 ) $ (1.17 ) $ 2,293 $ 0.01 $ (772,267 ) $ (2.84 ) $ (2,313 ) $ (0.01 )
Adjustments shown above (3) 441,816 1.62 299,261 1.10 5,043 0.02 741,077 2.73 21,546 0.08
Dilution attributable to share-based payments (4)                                      
Adjusted net income (loss) (5) $ (12,339 ) $ (0.05 ) $ (18,851 ) $ (0.07 ) $ 7,336   $ 0.03 $ (31,190 ) $ (0.11 ) $ 19,233   $ 0.07  
 
Common share and equivalents used for earnings (loss) per share (EPS):
Weighted average common shares outstanding 271,549 271,522 270,492 271,536 265,631
Dilutive stock options
Dilutive restricted shares and restricted share units           734         515  
Shares used to compute diluted EPS for adjusted net income (loss)   271,549     271,522     271,226     271,536     266,146  
(1)   The assumed income tax rate is 40% for all periods.
(2) Deferred tax valuation allowance has been adjusted to reflect the assumed income tax rate of 40% for all periods.
(3) Per share amounts are based on weighted average number of common shares outstanding.
(4) Represents dilution per share attributable to common share equivalents from in-the-money stock options, dilutive restricted shares and diluted restricted share units calculated in accordance with the treasury stock method.
(5) Adjusted net income (loss), a non-GAAP measure, includes adjustments for gains or losses from asset sales, unrealized gains or losses from derivative financial instruments, non-cash impairments and other items typically not included by securities analysts in published estimates.

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