EXCO Resources, Inc. (NYSE: XCO) ("EXCO") today announced operating and financial results for the third quarter 2014.
  • Adjusted EBITDA was $94 million for the third quarter 2014, which exceeded the mid-point of guidance.
  • Production was 33 Bcfe, or 358 Mmcfe per day, for the third quarter 2014, which was within our guidance.
  • Drilled 26 gross (11.6 net) and completed 21 gross (6.8 net) operated horizontal shale wells in the third quarter 2014.
  • Implemented cost reduction initiatives which resulted in oil and natural gas operating costs and general and administrative costs below the low-end of guidance for the third quarter 2014.
  • Enhanced our liquidity as a result of an increase to the borrowing base under our credit agreement.
  • Expect to reduce indebtedness and further enhance liquidity as a result of the pending sale of our interests in Compass Production Partners.

Jeff Benjamin, EXCO's chairman, commented, "We continue to demonstrate strong financial performance and execute on our key business objectives. The energy sector has recently experienced a decline in market valuation driven by lower commodity prices; however, we believe that our execution of several key transactions and fiscal discipline over the past year has positioned EXCO for future success. Our improved balance sheet, enhanced liquidity and hedging strategy will allow us to accomplish our business strategies through various commodity price cycles. Our financial position gives us the ability to actively pursue acquisitions as opportunities arise. We have also been impressed with the recent success of several operational initiatives that are expected to unlock additional value from our current asset base, including our enhanced completion methods and programs to optimize our base production."

Financial results

GAAP results were net income of $42 million, or $0.15 per diluted share, for the third quarter 2014 compared with net income of $2 million, or $0.01 per diluted share, for the second quarter 2014. The increase in net income was primarily due to volatility in commodity prices which resulted in higher unrealized gains on derivative contracts in the current quarter. This was partially offset by lower revenues in the current quarter due to a decrease in production and realized commodity prices.

Adjusted EBITDA for the third quarter 2014 was $94 million compared with $105 million for the second quarter 2014. Adjusted EBITDA is a non-GAAP measure and is computed using earnings before interest, taxes, depletion, depreciation and amortization, and is further adjusted for gains from asset sales, unrealized gains or losses from derivative financial instruments, impairments of our oil and natural gas properties, other non-cash income and expenses, and other items impacting comparability.

Adjusted net income, a non-GAAP measure, was $0.01 per diluted share for the third quarter 2014 compared with $0.03 per diluted share for the second quarter 2014. The non-GAAP adjustments include gains from asset sales, unrealized gains or losses from derivative financial instruments, non-cash asset impairments and other items typically not included by securities analysts in published estimates.

Oil, natural gas and natural gas liquids ("NGLs") production was 33 Bcfe, or 358 Mmcfe per day, for the third quarter 2014 compared with 35 Bcfe, or 383 Mmcfe per day, for the second quarter 2014. Third quarter 2014 production from the East Texas/North Louisiana region was 242 Mmcfe per day compared with 257 Mmcfe per day in the second quarter 2014. The decrease in production was primarily the result of normal production declines and the timing of completions based on our drilling program. The decrease was partially offset by the additional production from the 7 gross (4.0 net) operated wells turned-to-sales during the third quarter 2014 (including 2 gross (1.0 net) operated wells that were turned-to-sales on the last day of the quarter). Third quarter 2014 production from the South Texas region was 540 Mboe, or 5,870 Boe per day, compared with 596 Mboe, or 6,550 Boe per day, in the second quarter 2014. The decrease in production was primarily due to reduced completion activity which resulted in an increased inventory of wells that were drilled and waiting on completion at the end of the third quarter 2014. The reduced completion activity and inventory of wells was primarily due to wells waiting on the construction of our first centralized production facility in the region which became operational in the fourth quarter of 2014. The third quarter 2014 production in the Appalachia region was 56 Mmcfe per day compared with 62 Mmcfe per day in the second quarter 2014. The decrease in production was due to normal production declines and additional downtime due to planned pipeline maintenance. Our proportionate share of production from Compass Production Partners was 25 Mmcfe per day for both the third quarter 2014 and the second quarter 2014.

Oil, natural gas and NGL revenues for the third quarter 2014 were $151 million compared with $183 million for the second quarter 2014. Our average sales price per Mcfe decreased to $4.58 per Mcfe for the third quarter 2014 from $5.25 per Mcfe for the second quarter 2014. Our average sales price per Mcfe for the third quarter 2014 decreased primarily due to lower market prices for oil and natural gas compared to the second quarter 2014. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $153 million, or $4.65 per Mcfe, for the third quarter 2014, compared with $168 million, or $4.83 per Mcfe, for the second quarter 2014.

Our direct operating costs were $14 million, or $0.43 per Mcfe, for the third quarter 2014 compared with $16 million, or $0.45 per Mcfe, for the second quarter 2014. The lower direct operating costs were primarily due to the continued execution of cost reduction initiatives in the South Texas region including decreased salt water disposal costs and reduced reliance on third-party contractors.

Our general and administrative costs were $14 million for the third quarter 2014 compared with $20 million for the second quarter 2014. The decrease was primarily due to lower headcount from the reduction in force during the second quarter 2014. Also, we incurred severance costs and lease termination fees for unused office space in the second quarter of 2014 that we did not incur in the third quarter 2014.

Cash flows from operations before changes in working capital and other operating items impacting comparability, a non-GAAP measure, were $72 million for the third quarter 2014 compared with $84 million for the second quarter 2014. During the third quarter 2014, we primarily used our cash flows from operations to fund our drilling and development program.

Recent developments

Compass Production Partners sale

On October 6, 2014, we entered into an agreement to sell our 25.5% economic interest in Compass Production Partners, LP ("Compass") to an affiliate of Harbinger Group, Inc. for $119 million in cash. We intend to use the proceeds to reduce indebtedness under the revolving commitment of our credit agreement ("EXCO Resources Credit Agreement"). Our borrowing base under the EXCO Resources Credit Agreement will not be affected by this sale since Compass is not a guarantor subsidiary. In addition, our consolidated indebtedness will be reduced by our proportionate share of Compass's indebtedness upon closing of the sale. As of September 30, 2014, we proportionally consolidated $83 million of indebtedness related to Compass's credit agreement. The transaction is expected to close during the fourth quarter of 2014.

Borrowing base redetermination and liquidity update

On October 22, 2014, our borrowing base under the EXCO Resources Credit Agreement was increased from $875 million to $900 million. The increase in our borrowing base improves our liquidity and demonstrates the quality of our assets. EXCO had liquidity of $711 million as of September 30, 2014. On a pro forma basis as if the sale of our interest in Compass and the borrowing base redetermination had occurred on September 30, 2014, our liquidity would have been $855 million. The anticipated reduction in indebtedness as a result of the Compass sale will also improve the metrics utilized in the financial covenants under the EXCO Resources Credit Agreement.

Operations activity and outlook

We spent $91 million on development activities, drilling 26 gross (11.6 net) operated wells and completing 21 gross (6.8 net) operated wells in the third quarter 2014. Our development program during 2014 is focused on our properties in the Haynesville and Eagle Ford shales. Our diverse portfolio of oil and natural gas properties gives us optionality to make capital decisions to maximize our returns based on our evaluation of industry trends and commodity prices. We remain focused on efficiently managing our capital expenditures as part of our development program.

Our capital expenditure program for the fourth quarter 2014 will primarily focus on our properties in the Haynesville and Eagle Ford shales. Our development activities in the East Texas/North Louisiana region will focus on drilling and completion activities in the Haynesville and Bossier shales within DeSoto Parish, Louisiana. In addition, we will be completing wells that have been drilled in the Shelby area of East Texas. Our development activities in the South Texas region will primarily focus on drilling and completion activities in the Eagle Ford shale within our core area and limited drilling outside of our core area as part of a farmout agreement. Our first centralized production facility in the region became operational in the fourth quarter 2014 which allows us to begin production from our inventory of wells that were waiting on completion at the end of the third quarter 2014.

Our actual capital expenditures during the first, second and third quarter 2014 as well as our fourth quarter and full year 2014 forecast are presented in the following table.
                   
(in thousands) First Quarter 2014 Second Quarter 2014 Third Quarter 2014 Fourth Quarter Forecast Full Year 2014 Forecast
Capital expenditures (1):
Development capital expenditures $ 80,198 $ 78,245 $ 91,204 $ 91,353 $ 341,000
Field operations, gathering and water pipelines 8,518 9,447 (1,039 ) 5,074 22,000
Lease purchases 1,996 1,215 3,696 7,093 14,000
Seismic 8 150 179 1,663 2,000
Corporate and other   9,317   10,069   9,465     13,149   42,000
Total $ 100,037 $ 99,126 $ 103,505   $ 118,332 $ 421,000

(1) Excludes capital expenditures related to Compass, which funded its capital expenditures through internally generated cash flows and its credit agreement.

East Texas/North Louisiana

In the East Texas/North Louisiana region during the third quarter 2014, we operated an average of six drilling rigs primarily focused on manufacturing in our core area in DeSoto Parish, Louisiana. In DeSoto Parish, we drilled 15 gross (8.9 net) operated wells and completed 5 gross (3.0 net) wells during the quarter. We had an inventory of 12 gross (6.7 net) wells that were drilled and waiting on completion in DeSoto Parish at the end of the quarter, most of which will be turned-to-sales in the fourth quarter 2014. We have continued to optimize our well design by increasing the amount of proppant used in the hydraulic fracturing process on completions during the quarter. These changes in our well design are expected to improve our well performance and estimated ultimate recoveries. We are also in the process of completing our first cross-unit development in DeSoto Parish that includes drilling 5,000 to 7,000 foot laterals into a section bisected by a fault. The laterals on the cross-unit development are longer than our typical laterals of approximately 4,200 feet for Haynesville shale wells in DeSoto Parish. We plan to turn these wells to sales during the fourth quarter 2014.

In the Shelby area, we completed 2 gross (1.0 net) wells on the last day of the quarter. In addition, we have plans to complete and turn-to-sales 4 gross (1.9 net wells) in the fourth quarter 2014. Prior to 2014, our activity in this area has historically consisted of delineating the acreage, establishing infrastructure, and performing technical evaluations. Our drilling program during 2014 was designed to include enhanced completion methods, longer laterals and a more restricted flowback program. As part of our restricted flowback program, we have been managing the choke size to limit the production of the wells to 10 Mmcf per day. The restricted flowback limits the initial production of the wells; however, we anticipate it will increase the estimated ultimate recoveries. We have been encouraged by the results of the wells turned-to-sales in this area during 2014. The more conservative flowback, along with the other design changes, are yielding strong well performance as evidenced by a minimal reduction in flowing pressures over time. We drilled 8 gross (3.9 net) wells in the area during 2014 which includes 5 gross (2.4 net) in the Haynesville shale and 3 gross (1.5 net) in the Bossier shale. We are experiencing similar strong results from both the Haynesville and Bossier shale wells. We have approximately 250 operated undeveloped locations in this area which provide a platform for future growth.

We have spud a test well in the Bossier shale in DeSoto Parish in the fourth quarter 2014 to further assess the potential of the formation. The Bossier shale lies just above certain portions of the Haynesville shale and contains rich deposits of natural gas. We will utilize our technical expertise and recently enhanced completion methods that have proven to be successful in our Haynesville shale development. We will evaluate the results of the test in DeSoto Parish which could result in the addition of a significant number of drilling locations.

We completed our first refrac stimulation test on a mature Haynesville shale well in a fully developed unit within DeSoto Parish during the third quarter 2014. This test consisted of a second fracture stimulation treatment in an existing well to re-stimulate the shale reservoir. The refrac stimulation resulted in an increase in production for this well of 1.4 Mmcf per day on a more restricted choke as well as an increase in flowing casing pressure of 3,000 psi. The well continues to perform well as evidenced by the minimal reduction in production and pressure in the three months since the refrac stimulation. We expect to perform a similar treatment on other wells in the region and have plans for three additional refrac stimulation tests during the fourth quarter 2014. We have identified more than 270 operated Haynesville shale wells that are potential candidates for this treatment.

We have implemented several initiatives during the year to enhance and manage our base production in the region. This includes the initiation of a compression program, foamer injection program and the installation of artificial lift. Our compression program included the installation of two interim lateral compressor units during the quarter. We are currently studying additional interim lateral compression options and full field compression options in this region. We have seen sustained performance improvement from these initiatives as evidenced by a flattening of our base decline.

Additionally, BG Group's right to participate in our acquisition of oil and natural gas properties within an area of mutual interest in the East Texas/North Louisiana region expired in August 2014. We have significant experience and technical expertise in this region and this allows us to realize the full economic benefits of future acquisitions without the participation of a significant joint venture partner.

South Texas

In the South Texas region during the third quarter 2014, we operated an average of two drilling rigs focused on development of the Eagle Ford shale. We drilled 11 gross (2.7 net) operated wells and completed 14 gross (2.9 net) wells in the Eagle Ford shale during the quarter. Our drilling program during the quarter consisted of manufacturing and testing in the core area and adjacent areas under a farmout agreement. We have continued to expand our position in the area by earning additional acreage through drilling under the farmout agreement and leasing properties adjacent to our core area. We are preparing to test the Buda formation on a portion of our acreage later this year.

Our first centralized production facility within our core area became operational in the fourth quarter 2014 which allows us to begin production from wells connected to this system. At the end of the quarter, we had 31 gross (6.1 net) operated wells in the Eagle Ford shale that were drilled and waiting on completion, most of which will be turned-to-sales during the fourth quarter 2014. There are two additional centralized facilities within our core area that are currently in the construction phase.

We have realized significant improvements in our drilling performance since we acquired the assets in the South Texas region during 2013. This includes improved drilling times per well which are currently averaging 13 days from spud to rig release. We continue to evaluate updates to our well design including longer laterals and more proppant used in the hydraulic fracturing process. During the third quarter 2014, our shut-in volumes averaged 1,300 net Bbls of oil per day due to wells waiting on the centralized facilities as well as offset drilling, completion and maintenance activities. This is an increase from the shut-in volumes during the second quarter 2014 which averaged 1,100 net Bbls of oil per day. We are implementing initiatives to optimize and increase the efficiency of our production including the installation of artificial lift. The artificial lift units installed to-date have been successful in flattening our base decline.

Appalachia

In the Appalachia region, we remain focused on base production efficiency from our Marcellus shale and conventional assets. We have been able to effectively manage our base production declines as a result of increased automation and surveillance equipment to reduce downtime as well as artificial lift installations. We have also recently restructured our field organization to better align the operations personnel with the asset base and reduce our operating costs.

We are currently constructing a pad site for limited appraisal drilling in early 2015 targeting the Marcellus shale in Northeast Pennsylvania near recent successful well results. A significant portion of our acreage in the Marcellus shale is held-by-production, which allows us to control the timing of the development in this region.

Financial Data

Our consolidated balance sheets as of September 30, 2014 and December 31, 2013, consolidated statements of operations for the three months ended September 30, 2014, June 30, 2014, and September 30, 2013 and nine months ended September 30, 2014 and 2013 and consolidated statements of cash flows for the nine months ended September 30, 2014 and 2013, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release.

EXCO will host a conference call on Wednesday, October 29, 2014 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#24918635. 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 November 12, 2014. Please call (800) 585-8367 and enter conference ID#24918635 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.

We believe that it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution users of the financial statements not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the cautionary statements and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2013, filed with the Securities and Exchange Commission ("SEC") on February 26, 2014, and our other periodic filings with the SEC.

Our revenues, operating results and financial condition substantially depend on prevailing prices for oil and natural gas and the availability of capital from our credit agreement. Declines in oil or natural gas prices may have a material adverse effect on our financial condition, liquidity, results of operations, the amount of oil or natural gas that we can produce economically and the ability to fund our operations. 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 Resources, Inc.
Condensed Consolidated Balance Sheets
 
(in thousands) September 30, 2014 December 31, 2013
(Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 47,950 $ 50,483
Restricted cash 21,959 20,570
Accounts receivable, net:
Oil and natural gas 88,958 128,352
Joint interest 58,167 70,759
Other 6,027 18,022
Derivative financial instruments 19,230 8,226
Inventory and other   6,586     9,442  
Total current assets   248,877     305,854  
Equity investments 56,361 57,562
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized 354,225 425,307
Proved developed and undeveloped oil and natural gas properties 3,870,486 3,554,210
Accumulated depletion   (2,380,540 )   (2,183,464 )
Oil and natural gas properties, net   1,844,171     1,796,053  
Gathering assets 33,884 33,473
Accumulated depreciation and amortization   (11,617 )   (10,338 )
Gathering assets, net   22,267     23,135  
Office, field and other equipment, net 25,535 27,204
Deferred financing costs, net 33,166 28,807
Derivative financial instruments 8,813 6,829
Goodwill 163,155 163,155
Other assets   27     29  
Total assets $ 2,402,372   $ 2,408,628  
       
 
EXCO Resources, Inc.
Condensed Consolidated Balance Sheets
 
(in thousands, except per share and share data) September 30, 2014 December 31, 2013
(Unaudited)
Liabilities and shareholders' equity
Current liabilities:
Accounts payable and accrued liabilities $ 120,358 $ 109,217
Revenues and royalties payable 168,331 154,862
Drilling advances 51,547 22,971
Accrued interest payable 22,836 18,144
Current portion of asset retirement obligations 216 191
Income taxes payable
Derivative financial instruments 9,297 11,919
Current maturities of long-term debt       31,866  
Total current liabilities   372,585     349,170  
Long-term debt 1,549,439 1,858,912
Deferred income taxes
Derivative financial instruments 7,987 9,671
Asset retirement obligations and other long-term liabilities 45,319 42,970
Commitments and contingencies
Shareholders' equity:
Common stock, $0.001 par value; 350,000,000 authorized shares; 274,324,023 shares issued and 273,784,802 shares outstanding at September 30, 2014; 218,783,540 shares issued and 218,244,319 shares outstanding at December 31, 2013 270 215
Subscription rights, $0.001 par value; none issued and outstanding at September 30, 2014; 54,574,734 issued and outstanding at December 31, 2013 55
Additional paid-in capital 3,500,488 3,219,748
Accumulated deficit (3,066,237 ) (3,064,634 )
Treasury stock, at cost; 539,221 shares at September 30, 2014 and December 31, 2013   (7,479 )   (7,479 )
Total shareholders' equity   427,042     147,905  
Total liabilities and shareholders' equity $ 2,402,372   $ 2,408,628  
       
 
EXCO Resources, Inc.
Condensed Consolidated Statements of Operations
(Unaudited)
 
Three Months Ended Nine Months Ended
(in thousands, except per share data) September 30, 2014     June 30, 2014     September 30, 2013 September 30, 2014     September 30, 2013
Revenues:
Total revenues $ 151,042 $ 182,966 $ 165,314 $ 532,480 $ 453,869
Costs and expenses:
Oil and natural gas operating costs 14,099 15,827 17,187 48,713 42,706
Production and ad valorem taxes 7,978 7,364 6,074 22,951 15,303
Gathering and transportation 25,822 26,038 26,665 76,473 74,549
Depletion, depreciation and amortization 64,913 67,253 74,499 201,441 163,195
Impairment of oil and natural gas properties 10,707
Accretion of discount on asset retirement obligations 709 695 619 2,085 1,865
General and administrative 14,059 19,504 21,937 50,901 66,495
(Gain) loss on divestitures and other operating items   663     2,973     2,739     6,382     (179,503 )
Total costs and expenses   128,243     139,654     149,720     408,946     195,317  
Operating income 22,799 43,312 15,594 123,534 258,552
Other income (expense):
Interest expense, net (23,974 ) (25,968 ) (36,474 ) (70,106 ) (71,771 )
Gain (loss) on derivative financial instruments 42,844 (14,718 ) 7,443 (14,896 ) 19,175
Other income 53 77 94 176 340
Equity income (loss)   (153 )   (410 )   (85,308 )   548     (61,229 )
Total other income (expense)   18,770     (41,019 )   (114,245 )   (84,278 )   (113,485 )
Income (loss) before income taxes 41,569 2,293 (98,651 ) 39,256 145,067
Income tax expense                    
Net income (loss) $ 41,569   $ 2,293   $ (98,651 ) $ 39,256   $ 145,067  
Earnings (loss) per common share:
Basic:
Net income (loss) $ 0.15   $ 0.01   $ (0.46 ) $ 0.15   $ 0.68  
Weighted average common shares outstanding   270,631     270,492     215,056     267,316     214,877  
Diluted:
Net income (loss) $ 0.15   $ 0.01   $ (0.46 ) $ 0.15   $ 0.67  
Weighted average common shares and common share equivalents outstanding   272,066     271,226     215,056     267,690     215,195  
   
 
EXCO Resources, Inc.
Condensed Consolidated Statements of Cash Flows
(Unaudited)
 
Nine Months Ended September 30,
(in thousands) 2014     2013
Operating Activities:
Net income $ 39,256 $ 145,067
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization 201,441 163,195
Share-based compensation expense 4,370 9,493
Accretion of discount on asset retirement obligations 2,085 1,865
Impairment of oil and natural gas properties 10,707
(Income) loss from equity method investments (548 ) 61,229
(Gain) loss on derivative financial instruments 14,896 (19,175 )
Cash settlements (payments) of derivative financial instruments (32,187 ) 28,416
Amortization of deferred financing costs and discount on debt issuance 9,891 22,440
Gain on divestitures and other non-operating items (8 ) (186,466 )
Effect of changes in:
Accounts receivable 60,201 (32,121 )
Other current assets (1,135 ) 4,879
Accounts payable and other current liabilities   60,103     13,842  
Net cash provided by operating activities   358,365     223,371  
Investing Activities:
Additions to oil and natural gas properties, gathering assets and equipment (297,736 ) (180,603 )
Property acquisitions (12,987 ) (1,007,362 )
Proceeds from disposition of property and equipment 76,536 745,733
Restricted cash (1,389 ) 33,948
Net changes in advances to joint ventures (3,181 ) 10,055
Equity method investments   1,749     (363 )
Net cash used in investing activities   (237,008 )   (398,592 )
Financing Activities:
Borrowings under credit agreements 40,000 1,004,523
Repayments under credit agreements (884,970 ) (777,470 )
Proceeds received from issuance of 2022 Notes 500,000
Proceeds from issuance of common stock, net 271,760 1,712
Payment of common stock dividends (40,604 ) (32,237 )
Deferred financing costs and other   (10,076 )   (33,458 )
Net cash provided by (used in) financing activities   (123,890 )   163,070  
Net decrease in cash (2,533 ) (12,151 )
Cash at beginning of period   50,483     45,644  
Cash at end of period $ 47,950   $ 33,493  
Supplemental Cash Flow Information:
Cash interest payments $ 69,257 $ 74,949
Income tax payments
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation $ 4,432 $ 5,533
Capitalized interest 15,410 15,264
Issuance of common stock for director services 185 65
Accrued restricted stock dividends 255 349
Debt assumed upon formation of Compass, net 58,613
       
 
EXCO Resources, Inc.
Consolidated EBITDA
And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data
(Unaudited)
 
Three Months Ended Nine Months Ended
(in thousands) September 30, 2014     June 30, 2014     September 30, 2013 September 30, 2014     September 30, 2013
Net income (loss) $ 41,569 $ 2,293 $ (98,651 ) $ 39,256 $ 145,067
Interest expense 23,974 25,968 36,474 70,106 71,771
Income tax expense
Depletion, depreciation and amortization   64,913     67,253     74,499     201,441     163,195  
EBITDA(1) $ 130,456 $ 95,514 $ 12,322 $ 310,803 $ 380,033
Accretion of discount on asset retirement obligations 709 695 619 2,085 1,865
Impairment of oil and natural gas properties 10,707

(Gain) loss on divestitures and other items impacting comparability
1,747 6,775 2,653 11,122 (178,693 )
Equity (income) loss 153 410 85,308 (548 ) 61,229
Net (gains) losses on derivative financial instruments (42,844 ) 14,718 (7,443 ) 14,896 (19,175 )
Cash settlements (payments) on derivative financial instruments 2,282 (14,659 ) 10,904 (32,187 ) 28,416
Share based compensation expense   1,118     1,745     3,170     4,370     9,493  
Adjusted EBITDA (1) $ 93,621 $ 105,198 $ 107,533 $ 310,541 $ 293,875
Interest expense (23,974 ) (25,968 ) (36,474 ) (70,106 ) (71,771 )
Income tax expense
Amortization of deferred financing costs and discount 2,194 5,253 15,843 9,891 22,440
Other operating items impacting comparability (1,755 ) (6,775 ) (2,769 ) (11,130 ) (7,773 )
Changes in working capital   20,157     (9,920 )   (31,994 )   119,169     (13,400 )
Net cash provided by operating activities $ 90,243   $ 67,788   $ 52,139   $ 358,365   $ 223,371  
       
 
EXCO Resources, Inc.
Consolidated EBITDA
And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data
(Unaudited)
 
Three Months Ended Nine Months Ended
(in thousands)

September 30,2014
   

June 30,2014
   

September 30,2013

September 30,2014
   

September 30,2013
Statement of cash flow data:
Cash flow provided by (used in):
Operating activities $ 90,243 $ 67,788 $ 52,139 $ 358,365 $ 223,371
Investing activities (112,065 ) (101,199 ) (881,644 ) (237,008 ) (398,592 )
Financing activities 23,894 (15,223 ) 782,556 (123,890 ) 163,070
Other financial and operating data:
EBITDA(1) $ 130,456 $ 95,514 $ 12,322 $ 310,803 $ 380,033
Adjusted EBITDA(1) 93,621 105,198 107,533 310,541 293,875
 
(1) Earnings before interest, taxes, depreciation, depletion and amortization, or "EBITDA" represents net income 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, stock-based compensation and income or losses from equity method investments. We have 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 our credit agreement, the indenture governing our 7.5% senior notes due September 15, 2018 ("2018 Notes"), and the indenture governing our 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 us. Our 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 our 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 a company's operating, investing and financing activities. As such, we encourage investors 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 our 2018 Notes and the indenture governing our 2022 Notes.
       
 
EXCO Resources, Inc.
Consolidated Adjusted Net Income and Adjusted Net Income Reconciliations
(Unaudited)
 
Three Months Ended Nine Months Ended

September 30,2014
   

June 30,2014
   

September 30,2013

September 30,2014
   

September 30,2013
(in thousands, except per share amounts) Amount  

Pershare
Amount  

Pershare
Amount  

Pershare
Amount  

Pershare
Amount  

Pershare
Net income (loss), GAAP $ 41,569 $ 2,293 $ (98,651 ) $ 39,256 $ 145,067
Adjustments:
Total net (gains) losses on derivatives (42,844 ) 14,718 (7,443 ) 14,896 (19,175 )
Cash receipts (payments) on derivative financial instruments 2,282 (14,659 ) 10,904 (32,187 ) 28,416
Impairment of oil and natural gas properties 10,707
Adjustments included in equity (income) loss 94,580 (1,749 ) 94,950
(Gain) loss on divestitures and other items impacting comparability 1,747 6,775 2,653 11,122 (178,693 )
Deferred finance cost and discount on debt issuance amortization acceleration 3,099 13,183 3,471 16,718
Income taxes on above adjustments (1) 15,526 (3,973 ) (45,551 ) 1,779 18,831
Adjustment to deferred tax asset valuation allowance (2)   (16,628 )   (917 )   39,460     (15,702 )   (58,027 )
Total adjustments, net of taxes   (39,917 )   5,043     107,786     (18,370 )   (86,273 )
Adjusted net income $ 1,652   $ 7,336   $ 9,135   $ 20,886   $ 58,794  
 
Net income (loss), GAAP (3) $ 41,569 $ 0.15 $ 2,293 $ 0.01 $ (98,651 ) $ (0.46 ) $ 39,256 $ 0.15 $ 145,067 $ 0.68
Adjustments shown above (3) (39,917 ) (0.14 ) 5,043 0.02 107,786 0.50 (18,370 ) (0.07 ) (86,273 ) (0.40 )
Dilution attributable to share-based payments (4)                                     (0.01 )
Adjusted net income $ 1,652   $ 0.01   $ 7,336   $ 0.03 $ 9,135   $ 0.04   $ 20,886   $ 0.08   $ 58,794   $ 0.27  
 
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding 270,631 270,492 215,056 267,316 214,877
Dilutive stock options 274 8
Dilutive restricted shares   1,435     734     902     374     310  
Shares used to compute diluted EPS for adjusted net income   272,066     271,226     216,232     267,690     215,195  
 
(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 dilutive restricted shares calculated in accordance with the treasury stock method.
       
 
EXCO Resources, Inc.
Consolidated Cash Flow from Operations before Working Capital Changes and Other Operating Items
Impacting Comparability and Reconciliations
(Unaudited)
 
Three Months Ended Nine Months Ended
(in thousands) September 30, 2014   June 30, 2014   September 30, 2013 September 30, 2014   September 30, 2013
Cash flow from operations, GAAP $ 90,243 $ 67,788 $ 52,139 $ 358,365 $ 223,371
Net change in working capital (20,157 ) 9,920 31,994 (119,169 ) 13,400
Non-recurring other operating items   1,747     6,775   2,769   11,122     7,773
Cash flow from operations before changes in working capital and other operating items impacting comparability, non-GAAP measure (1) $ 71,833   $ 84,483 $ 86,902 $ 250,318   $ 244,544
 
(1) Cash flow from operations before working capital changes and other operating items impacting comparability is presented because management believes it is a useful financial indicator for companies in our 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. Cash flow from operations before changes in working capital 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 our on-going operating activities.
                 
 
EXCO Resources, Inc.
Summary of Operating Data
(Unaudited)
 
Three Months Ended % Three Months Ended % Nine Months Ended %
  September 30, 2014   June 30, 2014 Change September 30, 2014   September 30, 2013 Change September 30, 2014   September 30, 2013 Change
Production:
Oil (Mbbls) 537 579 (7 )% 537 383 40 % 1,709 535 219 %
Natural gas (Mmcf) 29,359 31,006 (5 )% 29,359 39,268 (25 )% 93,087 116,556 (20 )%
Natural gas liquids (Mbbls) 62 65 (5 )% 62 53 17 % 186 178 4 %
Total production (Mmcfe) (1) 32,953 34,870 (5 )% 32,953 41,884 (21 )% 104,457 120,834 (14 )%
Average daily production (Mmcfe) 358 383 (7 )% 358 455 (21 )% 383 443 (14 )%
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl) $ 94.50 $ 96.81 (2 )% $ 94.50 $ 102.60 (8 )% $ 93.11 $ 97.49 (4 )%
Natural gas (per Mcf) 3.36 4.04 (17 )% 3.36 3.17 6 % 3.95 3.39 17 %
Natural gas liquids (per Bbl) 27.44 27.42 % 27.44 32.04 (14 )% 30.12 35.12 (14 )%
Natural gas equivalent (per Mcfe) 4.58 5.25 (13 )% 4.58 3.95 16 % 5.10 3.76 36 %
Costs and expenses (per Mcfe):
Oil and natural gas operating costs $ 0.43 $ 0.45 (4 )% $ 0.43 $ 0.41 5 % $ 0.47 $ 0.35 34 %
Production and ad valorem taxes 0.24 0.21 14 % 0.24 0.15 60 % 0.22 0.13 69 %
Gathering and transportation 0.78 0.75 4 % 0.78 0.64 22 % 0.73 0.62 18 %
Depletion 1.93 1.89 2 % 1.93 1.74 11 % 1.89 1.30 45 %
Depreciation and amortization 0.04 0.04 % 0.04 0.04 % 0.04 0.05 (20 )%
 
(1) Mmcfe is calculated by converting one barrel of oil or natural gas liquids into six Mcf of natural gas.

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