EXCO Resources, Inc. Reports Third Quarter 2012 Results

EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced third quarter results for 2012.
  • Adjusted net income, a non-GAAP measure adjusting for non-cash gains and losses from derivative financial instruments (derivatives), non-cash ceiling test write-downs and items typically not included by securities analysts in published estimates, was $0.13 per diluted share for the third quarter 2012.
  • GAAP results were a net loss of $346 million, or $1.62 per diluted share for the third quarter 2012. The third quarter 2012 includes a $318 million pre-tax non-cash ceiling test write-down of oil and natural gas properties.
  • Oil, natural gas and natural gas liquids (NGLs) production was 47 Bcfe, or 512 Mmcfe per day, for the third quarter 2012 compared with 550 Mmcfe per day in the second quarter 2012 and 544 Mmcfe per day in the third quarter 2011. As forecast, for the third quarter 2012, Haynesville/Bossier production declined 8% from the third quarter 2011 as we have reduced our operated drilling rig count from 22 in 2011 to five currently. However, due to increased drilling in the Marcellus shale during 2011 and into 2012, year over year production increased 35% in our Appalachia region. Permian production was flat compared to the second quarter 2012 and third quarter 2011.
  • Oil, natural gas and NGL revenues, before cash settlements on derivatives, for the third quarter 2012 were $142 million compared with third quarter 2011 revenues of $207 million. Our average sales price per Mcfe decreased by 27% in the third quarter 2012 to $3.01 from $4.14 in the prior year's quarter. When the impacts of cash settlements from derivatives are considered, oil and natural gas and NGL revenues were $192 million for the third quarter 2012.
  • Adjusted earnings before interest, taxes, depreciation, depletion and amortization, ceiling test write-downs and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the third quarter 2012 were $123 million, compared with $163 million in the prior year's quarter.
  • Our direct operating costs were $0.37 per Mcfe for the third quarter 2012 compared with $0.42 per Mcfe for the third quarter 2011. We continue taking significant steps in reducing our operating costs in all of our operating areas in response to the low natural gas price environment. Specific actions implemented during 2012 include shutting in certain marginal producing wells, reducing compressor rentals, renegotiating water disposal arrangements and modifying chemical treatment programs.
  • TGGT’s average throughput was approximately 1.5 Bcf per day during the third quarter 2012. Our 50% share of TGGT’s adjusted net income in the third quarter 2012 was $14 million, after adjustments for certain non-cash items during the quarter.

Douglas H. Miller, EXCO’s Chief Executive Officer, commented, "During the third quarter, we met our production goals and, because of increases in average commodity prices, exceeded our revenue expectations. We continued our strong cost containment efforts and achieved reductions in drilling and completion costs, operating expenses and general and administrative expenses. We also exceeded our cash flow goals. So far in 2012, we have experienced cash flow in excess of our capital expenditures and reduced our outstanding debt under our revolving credit agreement.

"We are encouraged by recent strengthening in gas prices. Since September 27, 2012, we added approximately 110 Mmcf per day of swaps for 2013 at an average price of $3.94 per Mmbtu and also added additional swaps for 2014 and 2015 at prices in excess of $4.20 per Mmbtu.

"We are finalizing the redetermination of our borrowing base and expect the October 2012 redetermination will result in a $1.3 billion borrowing base. We continue to review monetization and joint venture opportunities on our conventional and midstream assets and also are reviewing a number of acquisition opportunities in the currently active producing property market."

Net income

Our reported net income (loss) shown below, a GAAP measure, includes certain items not typically included by securities analysts in their published estimates of financial results. The following table provides a reconciliation of our net income (loss) to the non-GAAP measure of adjusted net income:
      Three Months Ended     Nine Months Ended
September 30, 2012     September 30, 2011 September 30, 2012     September 30, 2011
(in thousands, except per share amounts) Amount    

Per

share
Amount    

Per

share
Amount    

Per

share
Amount    

Per

share
Net income (loss), GAAP $ (346,174 ) $ 84,945 $ (1,124,256 ) $ 189,248
Adjustments:
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes 70,986 (51,346 ) 144,339 (47,888 )
Non-cash write down of oil and natural gas properties, before taxes 318,044 1,022,709
Adjustments included in equity income 2,884 21,683
Non-recurring other operating items 1,103 21,587 9,728 27,542
Deferred finance cost amortization acceleration 3,000
Income taxes on above adjustments (1) (157,207 ) 11,904 (480,584 ) 8,139
Adjustment to deferred tax asset valuation allowance (2) 138,470   (33,978 ) 449,702   (75,699 )
Total adjustments, net of taxes 374,280   (51,833 ) 1,170,577   (87,906 )
Adjusted net income $ 28,106   $ 33,112   $ 46,321   $ 101,342  
 
Net income (loss), GAAP (3) $ (346,174 ) $ (1.62 ) $ 84,945 $ 0.40 $ (1,124,256 ) $ (5.25 ) $ 189,248 $ 0.89
Adjustments shown above (3) 374,280 1.75 (51,833 ) (0.24 ) 1,170,577 5.47 (87,906 ) (0.41 )
Dilution attributable to stock options (4)     (0.01 )   (0.01 )
Adjusted net income $ 28,106   $ 0.13   $ 33,112   $ 0.15   $ 46,321   $ 0.22   $ 101,342   $ 0.47  
 
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding 214,301 214,068 214,204 213,831
Dilutive stock options   2,246     3,336  
Shares used to compute diluted EPS for adjusted net income 214,301   216,314   214,204   217,167  
 

(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 stock equivalents from in-the-money stock options.
 

Cash flow

Our cash flow from operations before changes in working capital was $107 million for the third quarter 2012. We use our cash flow and available borrowing capacity in our credit agreement to fund our drilling and development programs.
         
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands) 2012     2011 2012     2011
Cash flow from operations, GAAP $ 134,309 $ 127,301 $ 414,777 $ 355,334
Net change in working capital (27,382 ) 7,811 (124,316 ) 39,422
Non-recurring other operating items   15,858   8,625   21,813
Cash flow from operations before changes in working capital and non-recurring other operating items, non-GAAP measure (1) $ 106,927   $ 150,970   $ 299,086   $ 416,569
 

(1)

Cash flow from operations before working capital changes and non-recurring other operating items are 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.  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. Non-recurring other operating items have been excluded as they do not reflect our on-going operating activities.
 

Operations activity and outlook

We spent $88 million on development and exploitation activities, drilling and completing 38 gross (18.2 net) operated wells in the third quarter 2012, compared with 36 gross (19.6 net) operated wells during the second quarter 2012. In addition, we participated in 2 gross (0.2 net) wells operated by others (OBO) during the third quarter 2012. We had an overall drilling success rate of 97% for the third quarter 2012. Our total capital expenditures, including leasing and net of acreage reimbursements from BG Group, were approximately $99 million in the third quarter 2012.

Our actual capital expenditures for the three months ended March 31, 2012, the three months ended June 30, 2012 and the three months ended September 30, 2012 and our projected capital spending for the remainder of 2012 are presented in the following table:

                     
(in thousands) Q1 Actuals Q2 Actuals Q3 Actuals

October -

December

Forecast
 

Full Year

Forecast
Capital expenditures:
Development capital $ 141,771 $ 97,107 $ 87,786 $ 78,336 $ 405,000
Gas gathering and water pipelines 533 163 309 1,995 3,000
Lease acquisitions and seismic (1) 5,570 4,125 (595 ) 2,900 12,000
Capitalized interest 6,302 6,223 5,967 5,508 24,000
Corporate and other 7,975   6,053   5,202   6,770   26,000
Total $ 162,151   $ 113,671   $ 98,669   $ 95,509   $ 470,000
 

(1)

 Net of acreage reimbursements from BG Group totaling $0.9 million, with $0.1 million being attributable to both the first and second quarter 2012 and $0.7 million attributable to the third quarter 2012.
 

Haynesville/Bossier Shale

Our horizontal Haynesville shale development program continues to be a significant asset for EXCO and continues to yield strong results. As of October 20, 2012, our Haynesville/Bossier shale operated production was 1,038 Mmcf per day gross (312.9 Mmcf per day net) and with the addition of net production from our OBO wells, we had 341.7 Mmcf per day of total Haynesville/Bossier shale net production. In response to low natural gas prices, we have significantly reduced our drilling program. In 2011, we had 22 operated rigs in the Haynesville/Bossier play. We began to reduce our rig count in late 2011 and by early July 2012, we reached an operated rig count of five. We currently have five operated rigs drilling in the play and will continue to assess product pricing and project economics and make further decisions on rig count. Our development drilling program for 2012 is focused in DeSoto Parish, Louisiana where we continue our 80-acre spacing manufacturing program. We currently have 31 units fully developed in the Haynesville in DeSoto Parish. During 2012, we plan to drill approximately 56 gross (22.5 net) operated wells in the Haynesville/Bosser shale play.

We drilled and completed 19 gross (7.0 net) operated horizontal Haynesville wells and participated in 2 gross (0.2 net) OBO Haynesville horizontal wells during the third quarter 2012. We utilized an average of five operated rigs and spud 10 operated horizontal wells during the quarter. We averaged one OBO rig drilling in the play and spud one OBO well during the quarter. We currently have no OBO rigs drilling. In total, we have 358 operated horizontal wells and 184 OBO horizontal wells flowing to sales.

The average initial production rate from our operated Haynesville horizontal wells completed in the third quarter 2012 in DeSoto Parish was 12.7 Mmcf per day with an average 7,754 psi flowing casing pressure on an average 18/64ths choke. This maximum choke size is indicative of our modified restricted choke management program in DeSoto Parish. We have completed 51 wells in eight development units in 2012 in DeSoto Parish and all of the wells have been managed with this modified choke program. Our well performance has been very consistent. The average initial production rate for all 51 wells completed in 2012 in DeSoto Parish was 12.8 Mmcf per day with an average 7,875 psi flowing casing pressure on an average 18/64ths choke.

We have a major cost reduction and efficiency program underway and are continuing to see improvements in drilling times, stimulation costs and overall capital efficiency. Our DeSoto Parish well costs in the fourth quarter 2011 averaged approximately $9.5 million per well. With the changes implemented to date, our current estimated well cost in the DeSoto Parish area is $8.2 million, approximately $1.3 million or 13.7% less than actual costs at year end 2011. The largest factors in our cost reduction efforts to date are fracture stimulation market conditions, fracture stimulation design changes, modified tubing design and changes to the installation procedure, reduced drilling times and overall improved management of all rental items. We expect to realize additional improvements in capital efficiency during the fourth quarter and are targeting $8.0 million per well by year end. We have realized significant improvements in lease operating cost efficiencies since year end 2011. From the fourth quarter 2011 to current, we have realized a 22% reduction in total direct lease operating costs. Our new restricted choke program has contributed to this reduction in operating expenses by reducing water production volumes and lowering our flowing gas temperatures. The repair and maintenance costs have been reduced by reallocating work schedules through company personnel and reducing third party services. Our operations control room in our Dallas headquarters plays a significant role in our well surveillance process. From this control room, we have the ability to continuously monitor and remotely control natural gas flow 24 hours per day, 365 days per year.

Marcellus Shale

Our gross Marcellus shale production as of October 20, 2012, was approximately 154 Mmcf per day (32.4 Mmcf per day net), which represents an increase of more than 37% since the end of 2011. For the week ended October 24, 2012, we had more than 19.5 Mmcf per day (4.0 Mmcf per day net) of production shut in due primarily to offset drilling and completion activities. We have implemented a development program within our acreage in Northeast Pennsylvania and are continuing an appraisal program in Central Pennsylvania. Most of our drilling activity will be in Lycoming County, Pennsylvania where we are realizing our best returns in the Marcellus shale, particularly in West Lycoming where our last completion had initial production of 6.9 Mmcf per day. However, we continue to see good results in Central Pennsylvania with initial production from our most recent wells averaging over 7.0 Mmcf per day. We are currently drilling with one operated rig. Our budget, as revised in February 2012, was to drill 49 gross (12.4 net) operated wells in the Marcellus shale play in our Appalachia region. Of the 49 wells, 46 gross (11.5 net) are development wells and 3 gross (0.9 net) are appraisal wells. We continue to evaluate our 2012 Marcellus program, which could impact our rig count, activity levels and number of wells turned to sales. Our net drilling dollars are reduced by the effect of the carry we receive from BG Group. Approximately $5.2 million of the carry remains available to us from BG Group as of September 30, 2012. We expect that the remaining carry will be used in the fourth quarter 2012.

During the third quarter 2012, we spud 3 new operated wells and drilled and completed 10 gross (2.9 net) operated wells in the Marcellus shale. These 10 completed wells include nine wells in Northeast Pennsylvania and one well in Central Pennsylvania. We are also focused on building our field infrastructure, particularly water handling lines, storage and disposal facilities, in support of our expected levels of activity. These infrastructure investments are expected to be the primary drivers to reduce our average development well costs.

Permian

We drilled and completed 9 gross (8.8 net) wells in our Sugg Ranch area during the third quarter 2012 with 89% drilling success. We are currently running one operated rig and plan to drill and complete 36 gross (35.2 net) wells in 2012. Economics for this drilling activity typically have rates-of-return in excess of 50%. In the third quarter, our production averaged approximately 4,100 barrels per day of net oil equivalents which was essentially flat with the third quarter 2011. This average production rate consisted of 1,500 net barrels of oil, 6,900 net Mmcf of natural gas, and 1,400 net barrels of natural gas liquids per day.

Based on industry results surrounding our Permian acreage position, we are continuing to evaluate our shale potential. We have tested both the Wolfcamp and Cline shale formations vertically in several wells and continue to collect and analyze core samples.

TGGT

Our jointly held midstream company, TGGT, had total throughput averaging approximately 1.5 Bcf per day for the third quarter 2012. TGGT’s adjusted EBITDA of $42 million for the third quarter 2012 was a 48% increase over TGGT’s adjusted EBITDA for the third quarter 2011.

The improvement in EBITDA in the third quarter 2012 is primarily attributable to reduced operating expenses as well as increased throughput from third party producers in the Holly area. TGGT's major focus in the fourth quarter 2012 will be continued reduction of operating expenses through the release of rental units and discontinuation of equipment leases where appropriate. In order to release rental units, TGGT is finalizing the installation and start up of owned treating facilities in the Holly area.

In our Shelby area, TGGT's major infrastructure development and capital projects in the Shelby area are concluded for 2012. In the legacy East Texas area, TGGT anticipates increased throughput from customers drilling horizontal Cotton Valley wells.

TGGT's capital spending for the third quarter of 2012 was $11 million and total capital spending for the first nine months of 2012 was $108 million. We expect TGGT will spend approximately $24 million during the fourth quarter 2012. The additional capital spending will be primarily in the Holly area and legacy East Texas areas associated with pipeline laterals, permanent treating facilities and well connects for third party producers.

Financial Data

Our consolidated balance sheets as of September 30, 2012 and December 31, 2011 and consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011, and consolidated statements of cash flows for the nine months ended September 30, 2012 and 2011, are included on the following pages. We have also included reconciliations of non-GAAP financial measures referred to in this press release which have not been previously reconciled.

EXCO will host a conference call on Tuesday, October 30, 2012 at 8:00 a.m. (Dallas 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# 30479650. 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, after market close, on EXCO’s website on Monday, October 29, 2012.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., November 13, 2012. Please call (800) 585-8367 and enter conference ID# 30479650 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 EXCO’s Chairman, Douglas H. Miller, or its President, Stephen F. Smith, 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. You are cautioned not to place undue reliance on a forward-looking statement. When considering our forward-looking statements, keep in mind the risk factors and other cautionary statements in this press release and the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2011, and our other periodic filings with the SEC.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flow, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

The SEC permits oil and natural gas companies in filings made with the SEC to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC permits optional disclosure of “probable” and “possible” reserves in its filings with the SEC. EXCO may use broader terms to describe additional reserve opportunities such as “potential,” “unproved,” or “unbooked potential,” to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable or possible reserves and accordingly are subject to substantially greater risk of actually being realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third party engineers or appraisers. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2011, which is available on our website at www.excoresources.com under the Investor Relations tab.
       

EXCO Resources, Inc.

Consolidated balance sheets
 
(in thousands) September 30, 2012 December 31, 2011
(Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 73,553 $ 31,997
Restricted cash 67,306 155,925
Accounts receivable, net:
Oil and natural gas 63,443 88,518
Joint interest 58,886 170,918
Other 31,755 28,488
Inventory 6,591 8,345
Derivative financial instruments 57,997 164,002
Other 17,098   29,815  
Total current assets 376,629   678,008  
Equity investments 336,495 302,833
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized 546,477 667,342
Proved developed and undeveloped oil and natural gas properties 2,852,748 3,392,146
Accumulated depletion (1,893,294 ) (1,657,165 )
Oil and natural gas properties, net 1,505,931   2,402,323  
Gas gathering assets 130,792 136,203
Accumulated depreciation and amortization (32,818 ) (29,104 )
Gas gathering assets, net 97,974   107,099  
Office, field and other equipment, net 22,422 42,384
Deferred financing costs, net 23,938 29,622
Derivative financial instruments 8,391 11,034
Goodwill 218,256 218,256
Other assets 28   28  
Total assets $ 2,590,064   $ 3,791,587  
       

EXCO Resources, Inc.

Consolidated balance sheets
 
(in thousands, except share data) September 30, 2012 December 31, 2011
(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities $ 96,888 $ 117,968
Revenues and royalties payable 118,027 148,926
Accrued interest payable 3,233 17,973
Current portion of asset retirement obligations 732 732
Income taxes payable
Derivative financial instruments 2,948   1,800  
Total current liabilities 221,828   287,399  
Long-term debt 1,848,678 1,887,828
Deferred income taxes
Derivative financial instruments 34,542
Asset retirement obligations and other long-term liabilities 61,093 58,028
Commitments and contingencies
Shareholders’ equity:
Preferred stock, $0.001 par value; 10,000,000 authorized shares; none issued and outstanding
Common stock, $0.001 par value; 350,000,000 authorized shares; 217,154,647 shares issued and 216,615,426 shares outstanding at September 30, 2012; 217,245,504 shares issued and 216,706,283 shares outstanding at December 31, 2011 215 215
Additional paid-in capital 3,196,871 3,181,063
Accumulated deficit (2,765,684 ) (1,615,467 )
Treasury stock, at cost; 539,221 shares at September 30, 2012 and December 31, 2011 (7,479 ) (7,479 )
Total shareholders’ equity 423,923   1,558,332  
Total liabilities and shareholders’ equity $ 2,590,064   $ 3,791,587  
       

EXCO Resources, Inc.

Consolidated statements of operations

(Unaudited)
 

Three Months Ended

September 30,

Nine Months Ended

September 30,
(in thousands, except per share data) 2012     2011 2012     2011
Revenues:
Oil and natural gas $ 141,621 $ 207,274 $ 394,447 $ 575,330
Costs and expenses:
Oil and natural gas operating costs 17,425 21,101 59,084 60,843
Production and ad valorem taxes 6,689 6,653 20,671 18,700
Gathering and transportation 25,847 22,279 78,183 59,069
Depreciation, depletion and amortization 70,589 100,491 247,508 253,833
Write-down of oil and natural gas properties 318,044 1,022,709
Accretion of discount on asset retirement obligations 985 938 2,896 2,728
General and administrative 22,052 29,875 62,194 76,435
Other operating items 1,011   21,045   9,346   25,171  
Total costs and expenses 462,642   202,382   1,502,591   496,779  
Operating income (loss) (321,021 ) 4,892 (1,108,144 ) 78,551
Other income (expense):
Interest expense (17,935 ) (15,090 ) (55,068 ) (43,585 )
Gain (loss) on derivative financial instruments (20,261 ) 84,284 18,346 130,978
Other income 149 193 589 555
Equity income 12,894   10,666   20,021   22,749  
Total other income (expense) (25,153 ) 80,053   (16,112 ) 110,697  
Income (loss) before income taxes (346,174 ) 84,945 (1,124,256 ) 189,248
Income tax expense        
Net income (loss) $ (346,174 ) $ 84,945   $ (1,124,256 ) $ 189,248  
Earnings (loss) per common share:
Basic:
Net income (loss) $ (1.62 ) $ 0.40   $ (5.25 ) $ 0.89  
Weighted average common shares outstanding 214,301   214,068   214,204   213,831  
Diluted:
Net income (loss) $ (1.62 ) $ 0.39   $ (5.25 ) $ 0.87  
Weighted average common and common equivalent shares outstanding 214,301   216,314   214,204   217,167  
 

EXCO Resources, Inc.

Consolidated statement of cash flows

(Unaudited)
 
Nine Months Ended September 30,
(in thousands) 2012   2011
Operating Activities:
Net income (loss) $ (1,124,256 ) $ 189,248
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 247,508 253,833
Share-based compensation expense 8,072 7,537
Accretion of discount on asset retirement obligations 2,896 2,728
Write-down of oil and natural gas properties and other impairment losses on long-lived assets 1,022,709 6,800
Income from equity investments (20,021 ) (22,749 )
Non-cash change in fair value of derivatives 144,339 (47,888 )
Deferred income taxes
Amortization of deferred financing costs and discount on the 2018 Notes 8,111 6,318
(Gain) loss on divestitures and sale of other assets 1,103 (1,071 )
Effect of changes in:
Accounts receivable 133,537 (82,803 )
Other current assets 6,019 (6,397 )
Accounts payable and other current liabilities (15,240 ) 49,778  
Net cash provided by operating activities 414,777   355,334  
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment (409,616 ) (754,493 )
Property acquisitions (2,748 ) (737,357 )
Equity method investments (12,997 ) (13,969 )
Proceeds from disposition of property and equipment 22,640 428,332
Restricted cash 88,619 44,378
Net changes in advances (to) from Appalachia JV 6,849 3,306
Distributions from equity method investments 125,000
Deposit on acquisitions 464,151
Other   (5,750 )
Net cash used in investing activities (307,253 ) (446,402 )
Financing Activities:
Borrowings under the EXCO Resources Credit Agreement 53,000 521,000
Repayments under the EXCO Resources Credit Agreement (93,000 ) (397,500 )
Proceeds from issuance of common stock 1,397 11,776
Payment of common stock dividends (25,740 ) (25,673 )
Deferred financing costs and other (1,625 ) (6,346 )
Net cash provided by (used in) financing activities (65,968 ) 103,257  
Net increase in cash 41,556 12,189
Cash at beginning of period 31,997   44,229  
Cash at end of period $ 73,553   $ 56,418  
 
Supplemental Cash Flow Information:
Cash interest payments $ 78,447   $ 70,758  
Income tax payments $   $ 1,458  
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation $ 5,778   $ 4,309  
Capitalized interest $ 18,492   $ 23,155  
Issuance of common stock for director services $ 561   $ 50  
Accrued restricted stock dividends $ 221   $  
     

EXCO Resources, Inc.

Consolidated EBITDA

And Adjusted EBITDA reconciliations and statement of cash flow data

(Unaudited)
 
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands) 2012       2011 2012   2011
Net income (loss) $ (346,174 ) $ 84,945 $ (1,124,256 ) $ 189,248
Interest expense 17,935 15,090 55,068 43,585
Income tax expense
Depreciation, depletion and amortization   70,589     100,491     247,508     253,833  
EBITDA(1) (257,650 ) 200,526 (821,680 ) 486,666
Accretion of discount on asset retirement obligations 985 938 2,896 2,728
Non-cash write down of oil and natural gas properties 318,044 1,022,709
Non-recurring other operating items 1,103 21,587 9,728 27,542
Equity income (12,894 ) (10,666 ) (20,021 ) (22,749 )
Non-cash change in fair value of derivative financial instruments 70,986 (51,346 ) 144,339 (47,888 )
Stock based compensation expense   2,617     2,450     8,072     7,537  
Adjusted EBITDA (1) $ 123,191 $ 163,489 $ 346,043 $ 453,836
Interest expense (17,935 ) (15,090 ) (55,068 ) (43,585 )
Income tax expense
Amortization of deferred financing costs and discount on the 2018 Notes 1,671 2,571 8,111 6,318
Deferred income taxes
Non-recurring other operating items (15,858 ) (8,625 ) (21,813 )
Changes in working capital   27,382     (7,811 )   124,316     (39,422 )
Net cash provided by operating activities $ 134,309   $ 127,301   $ 414,777   $ 355,334  
 
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands)   2012     2011     2012     2011  
Statement of cash flow data (unaudited):
Cash flow provided by (used in):
Operating activities $ 134,309 $ 127,301 $ 414,777 $ 355,334
Investing activities (105,642 ) (249,217 ) (307,253 ) (446,402 )
Financing activities (7,510 ) 113,148 (65,968 ) 103,257
Other financial and operating data:
EBITDA(1) (257,650 ) 200,526 (821,680 ) 486,666
Adjusted EBITDA(1) 123,191 163,489 346,043 453,836
 

(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 non-recurring other operating items, accretion of discount on asset retirement obligations, non-cash changes in the fair value of derivatives, non-cash write-downs 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, these measures are used in covenant calculations required under our credit agreement and the indenture governing our 7.5% senior notes due September 15, 2018.  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 generally accepted accounting principles, or 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.
         

TGGT Holdings, LLC

EBITDA and Adjusted EBITDA reconciliation

(Unaudited)
 
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands) 2012     2011 2012     2011
 
Equity income (loss) $ 12,894 $ 10,666 $ 20,021 $ 22,749
Amortization of the difference in the historical basis of our contribution to TGGT (402 ) (402 ) (1,206 ) (1,206 )
Equity (gain) loss of other investments (1,309 ) (574 ) 1,285   56  
EXCO's share of TGGT net income 11,183 9,690 20,100 21,599
BG Group's share of TGGT net income 11,183   9,690   20,100   21,599  
TGGT net income 22,366 19,380 40,200 43,198
Interest expense 5,356 2,302 11,913 6,169
Margin tax expense 32 399 300 1,118
Depreciation and amortization 8,967   6,769   23,790   19,001  
TGGT EBITDA(1) 36,721 28,850 76,203 69,486
Asset impairments and non-recurring other operating items 5,767   (167 ) 43,365   13,293  
TGGT Adjusted EBITDA(1) $ 42,488   $ 28,683   $ 119,568   $ 82,779  
EXCO's share of TGGT Adjusted EBITDA (2) $ 21,244   $ 14,342   $ 59,784   $ 41,390  
 

(1)

Earnings before interest, taxes, depreciation, depletion and amortization, or “EBITDA” represents net income adjusted to exclude interest expense, income taxes and depreciation and amortization. “Adjusted EBITDA” represents EBITDA adjusted to exclude asset impairments, gains and losses on divestitures and non-recurring other operating items. 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. 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 generally accepted accounting principles, or 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.
 

(2)

Represents our 50% equity share in TGGT.
 
       

 

TGGT Holdings, LLC

Computation of adjusted net income

(Unaudited)
 
Three Months Ended Nine Months Ended
September 30, September 30,
(in thousands) 2012     2011 2012     2011
Net income, GAAP $ 22,366 $ 19,380 $ 40,200 $ 43,198
Adjustments:
Loss on asset disposal 241 50 1,640 1,415
Asset impairment, net of insurance recoveries 4,618 (2,917 ) 39,961 9,178
Other non-cash items 908 2,700 1,764 2,700
Income taxes on above adjustments      
Total adjustments, net of taxes 5,767   (167 ) 43,365   13,293
Adjusted net income $ 28,133   $ 19,213   $ 83,565   $ 56,491
 
EXCO's 50% share of TGGT's adjusted net income (1) $ 14,067   $ 9,607   $ 41,783   $ 28,246
 

(1)

TGGT’s net income, computed in accordance with GAAP, includes certain items not typically included by securities analysts in published estimates of financial results.  This table provides a reconciliation of GAAP net income to a non-GAAP measure of adjusted net income.
 
                 

EXCO Resources, Inc.

Summary of operating data
 
Three Months Ended Nine Months Ended
September 30, % September 30, %
  2012   2011 Change 2012     2011 Change
Production:
Oil (Mbbls) 170 182 (7 )% 544 553 (2 )%
Natural gas liquids (Mbbls) 129 131 (2 )% 382 379 1 %
Natural gas (Mmcf) 45,330 48,178 (6 )% 140,484 127,395 10 %
Total production (Mmcfe) (1) 47,124 50,056 (6 )% 146,040 132,987 10 %
Average daily production (Mmcfe) 512 544 (6 )% 533 487 9 %
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl) $ 86.87 $ 85.69 1 % $ 90.33 $ 91.53 (1 )%
Natural gas liquids (per Bbl) 38.64 59.93 (36 )% 43.71 57.94 (25 )%
Natural gas (per Mcf) 2.69 3.82 (30 )% 2.34 3.95 (41 )%
Natural gas equivalent (per Mcfe) 3.01 4.14 (27 )% 2.70 4.33 (38 )%
Costs and expenses (per Mcfe):
Oil and natural gas operating costs $ 0.37 $ 0.42 (12 )% $ 0.40 $ 0.46 (13 )%
Production and ad valorem taxes 0.14 0.13 8 % 0.14 0.14 %
Gathering and transportation 0.55 0.45 22 % 0.54 0.44 23 %
Depletion 1.42 1.92 (26 )% 1.62 1.80 (10 )%
Depreciation and amortization 0.07 0.09 (22 )% 0.08 0.10 (20 )%
General and administrative 0.47 0.60 (22 )% 0.43 0.57 (25 )%
 

(1)

Effective with the second quarter 2012, we began reporting NGL volumes separately and have recast prior period volumes to conform to current period reporting.
 

Copyright Business Wire 2010

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