EXCO Resources, Inc. Reports Second Quarter 2012 Results

EXCO Resources, Inc. (NYSE:XCO) (“EXCO”) today announced second 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 $0.05 per diluted share for the second quarter 2012.
  • GAAP results were a net loss of $2.32 per diluted share for the second quarter 2012. The second quarter 2012 includes a $429 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 50 Bcfe, or 550 Mmcfe per day, for the second quarter 2012 compared with 537 Mmcfe per day in the first quarter 2012 and 504 Mmcfe per day in the second quarter 2011. Effective with the second quarter 2012, we began reporting NGL volumes separately and have recast prior period volumes to conform to current period reporting. While our production increases from 2011 are primarily attributable to volumes from the Haynesville shale, we have reduced drilling activity in the Haynesville shale in 2012 and future quarterly production volumes are expected to decline as a result. Due to increased drilling in the Marcellus shale, year over year production increased 31% in our Appalachia region. Our Permian production was relatively flat with the prior quarter and prior year.
  • Oil, natural gas and NGL revenues for the second quarter 2012 were $118 million compared with second quarter 2011 revenues of $207 million. Our average sales price per Mcfe decreased by 48% from the prior year resulting in lower revenues despite a 9% increase in production. When the impacts of cash settlements from our oil and natural gas derivatives are considered, oil and natural gas revenues were $180 million for the second quarter 2012.
  • Adjusted earnings before interest, taxes, depreciation, depletion and amortization and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the second quarter 2012 was $112 million.
  • Our direct operating costs were $0.38 per Mcfe for the second quarter 2012 compared with $0.45 per Mcfe for the second quarter 2011. We continued 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 the first six months of 2012 included 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 second quarter 2012. We use the equity method to account for our investment in TGGT. During the second quarter 2012, our 50% interest in TGGT’s operations provided equity income of $16 million. This was an increase of $6.1 million over our net share of TGGT's second quarter 2011 net income, adjusted for certain non-recurring items (a non-GAAP measure).

Douglas H. Miller, EXCO’s Chief Executive Officer, commented, "During the second quarter of 2012, we increased our production levels from the 2011 second quarter by 9% and also increased production compared to the first quarter of 2012. The production level exceeded the top of our guidance target of 545 Mmcfe per day, in spite of a reduction in rigs from 14 at the end of the first quarter of 2012 to eight in July.

"We had another successful quarter drilling in the Haynesville shale in Louisiana and East Texas and we continued our successful drilling in the Marcellus shale in Lycoming County in Pennsylvania. We also experienced encouraging results from four successful Marcellus completions in Central Pennsylvania. Our cost containment efforts across the company were very successful in the second quarter with continued reductions in operating expenses and general administrative costs as well as continued decreases in drilling and completion costs.

"We continue to review a number of possible producing property acquisitions in our existing operating areas. Also, we continue to market an interest in our conventional assets to equity partners, and we have been working with BG Group and a strategic advisor to begin marketing our TGGT midstream entity.

"We are encouraged by the better than expected performance from our base production and are also encouraged by the recent strengthening of the natural gas price. Although the natural gas market remains challenging, we believe our financial position and liquidity are sufficient to allow us to continue to meet the challenges presented."

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 non-GAAP measures of adjusted net income:
  Three months ended   Six months ended
June 30, 2012   June 30, 2011 June 30, 2012   June 30, 2011
(in thousands, except per share amounts) Amount   Per share Amount   Per share Amount   Per share Amount   Per share
Net income (loss), GAAP $ (496,433 ) $ 82,362 $ (778,082 ) $ 104,303
Adjustments:
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes 77,073 (20,056 ) 73,353 3,458
Non-cash write down of oil and natural gas properties, before taxes 428,801 704,665
Adjustments included in equity income 18,799
Non-recurring other operating items 6,673 2,980 8,625 5,955
Deferred finance cost amortization acceleration 3,000 3,000
Income taxes on above adjustments (1) (206,219 ) 6,830 (323,377 ) (3,765 )
Adjustment to deferred tax asset valuation allowance (2) 198,573   (32,944 ) 311,233   (41,721 )
Total adjustments, net of taxes 507,901   (43,190 ) 796,298   (36,073 )
Adjusted net income $ 11,468   $ 39,172   $ 18,216   $ 68,230  
 
Net income (loss), GAAP (3) $ (496,433 ) $ (2.32 ) $ 82,362 $ 0.39 $ (778,082 ) $ (3.63 ) $ 104,303 $ 0.49
Adjustments shown above (3) 507,901 2.37 (43,190 ) (0.20 ) 796,298 3.72 (36,073 ) (0.17 )
Dilution attributable to stock options (4)   (0.01 )   (0.01 )
Adjusted net income $ 11,468   $ 0.05   $ 39,172   $ 0.18   $ 18,216   $ 0.09   $ 68,230   $ 0.31  
 
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding 214,164 213,888 214,154 213,710
Dilutive stock options   3,625     3,603  
Shares used to compute diluted EPS for adjusted net income 214,164   217,513   214,154   217,313  
(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 $97 million for the second 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   Six months ended
June 30, June 30,
(in thousands) 2012   2011 2012   2011
Cash flow from operations, GAAP $ 135,345 $ 148,960 $ 280,468 $ 228,033
Net change in working capital (45,355 ) 372 (96,934 ) 31,611
Non-recurring other operating items 6,673   2,980   8,625   5,955
Cash flow from operations before changes in working capital and non-recurring other operating items, non-GAAP measure (1) $ 96,663   $ 152,312   $ 192,159   $ 265,599
 

(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 $97 million on development and exploitation activities, drilling and completing 36 gross (19.6 net) operated wells in the second quarter 2012, compared with 42 gross (18.4 net) operated wells during the first quarter 2012. In addition, we participated in 5 gross (0.2 net) wells operated by others (OBO) during the second quarter 2012. We had an overall drilling success rate of 100% for the second quarter 2012. Our total capital expenditures, including leasing and net of acreage reimbursements from BG Group, were approximately $114 million in the second quarter 2012.

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

(in thousands)   Q1 2012 Actuals   Q2 2012 Actuals   July - December 2012 capital forecast   2012 Full Year Forecast
Capital expenditures:
Development capital $ 141,771 $ 97,107 $ 156,122 $ 395,000
Gas gathering and water pipelines 533 163 4,804 5,500
Lease acquisitions and seismic (1) 5,570 4,125 9,805 19,500
Capitalized interest 6,302 6,223 12,075 24,600
Corporate and other 7,975   6,053   11,372   25,400
Total $ 162,151   $ 113,671   $ 194,178   $ 470,000
 

(1)  Net of acreage reimbursements from BG Group totaling $0.2 million, with $0.1 million being attributable to both the first and second 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 July 17, 2012, our Haynesville/Bossier shale operated production was 1,178 Mmcf per day gross (350.6 Mmcf per day net) and with the addition of net production from our OBO wells, we had 381.8 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 averaged 22 operated rigs in the Haynesville/Bossier shale throughout the year. We began to reduce our rig count in late 2011 and have further reduced the rig count in the first half of 2012. We currently have five active operated rigs drilling in the play. We will evaluate product pricing and project economics and make further decisions on rig count throughout the year. Our development drilling program for 2012 is focused in DeSoto Parish, Louisiana where we continue our 80-acre spacing manufacturing program. Our assets in San Augustine and Nacogdoches Counties, Texas have been delineated and tested and almost all of our core acreage in that area is held by production. We do not have plans to drill additional operated wells in the East Texas area in 2012, although we are participating in two OBO wells in East Texas over the remainder of 2012. Our focus in East Texas is on evaluation and planning for future full field development. During 2012, we plan to drill approximately 60 gross (22.2 net) operated wells in the Haynesville/Bossier shale play.

We drilled and completed 15 gross (6.8 net) operated horizontal Haynesville/Bossier wells and participated in 5 gross (0.2 net) OBO Haynesville/Bossier horizontal wells during the second quarter of 2012. We utilized an average of seven operated rigs and spud 15 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 one OBO rig drilling. In total, we have 346 operated horizontal wells and 181 OBO horizontal wells flowing to sales.

The average initial production rate from our operated Haynesville horizontal wells completed in the second quarter 2012 in DeSoto Parish was 12.1 Mmcf per day with an average 7,500 psi flowing casing pressure on an average 18/64ths choke. This 18/64ths choke size is indicative of our new restricted choke management program we have implemented in DeSoto Parish, based on the strong results we realized in our East Texas area. Two wells were completed in the second quarter 2012 in San Augustine County, Texas. The average IP was 13.4 Mmcf per day with an average 8,925 psi flowing casing pressure on an average 18/64ths choke.

We have a major cost reduction and efficiency program underway and are beginning to see significant improvements in capital efficiency. Our DeSoto Parish well costs in the fourth quarter 2011 were approximately $9.5 million per well. With the changes implemented to date, our current estimated well cost in the DeSoto Parish area is $8.3 million, approximately $1.2 million or 13% less than actual costs at year end 2011. We expect to realize additional improvements in capital efficiency during 2012 and are targeting $8.0 million per well by year end 2012. We have realized significant improvements in lease operating cost efficiencies since year end 2011. From the fourth quarter of 2011 to current, we have realized a 21% reduction in total direct lease operating costs. Our new restricted choke program has reduced water production volumes and lowered our flowing gas temperatures, both having favorable impacts on operating expenses. The repair and maintenance costs have been reduced by reallocating work schedules through company personnel and reducing third party services.

Marcellus Shale

Our current gross Marcellus shale production as of July 18, 2012, is approximately 146 Mmcf per day (30.1 Mmcf per day net), which represents an increase of more than 28% since the end of 2011. We have more than 32 Mmcf per day (6.6 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 concluding an appraisal program in Central Pennsylvania. 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. Most of our drilling activity will be in Lycoming County, Pennsylvania where we are realizing our best returns in the Marcellus shale. However, our last four wells in Central Pennsylvania realized average IPs of 7.2 Mmcf per day from average lateral lengths of approximately 4,700 feet, exceeding our forecasts. During the second quarter of 2012, we utilized three operated rigs in the play. We are currently drilling with one operated rig. 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 $8.0 million of the carry remains available to us from BG Group as of June 30, 2012. We expect that the remaining carry will be used in the third quarter 2012.

During the second quarter 2012, we spud 9 new operated wells and drilled and completed 12 gross (4.0 net) operated wells in the Marcellus shale. These 12 completed wells included eight wells in Northeast Pennsylvania and four wells 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 second quarter 2012 with 100% drilling success. We are currently running two operated rigs and plan to drill and complete 36 gross (34.9 net) wells in 2012. Economics for this drilling activity typically have rates-of-return in excess of 50%. In the second quarter, our production averaged approximately 4,200 barrels per day of net oil equivalents which was a 5% increase over the second quarter of 2011. This average production rate consisted of 1,600 net barrels of oil, 7.0 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 are testing potential formations vertically in addition to routine core sample analysis. Based on those results, we may spud a horizontal test well during the second half of 2012.

Midstream

Our jointly held midstream company, TGGT, had total throughput which averaged approximately 1.5 Bcf per day for the second quarter of 2012. TGGT’s adjusted EBITDA of $42 million for the second quarter of 2012 was a 22% increase over TGGT’s adjusted EBITDA for the first quarter of 2012.

The EBITDA increase in the second quarter of 2012 is primarily attributable to the significant reduction in operating expenses as TGGT released rental units, canceled equipment leases and discontinued use of third party treating following TGGT's treating facilities becoming fully operational. TGGT continues to evaluate additional operational opportunities to maximize efficiencies and further reduce operating expenses.

In our Shelby area, a major pipeline and treating facility capable of treating all the current Shelby volumes became operational in the second quarter of 2012. Following the completion of the pipeline and the treating facility, TGGT's major infrastructure development and capital projects in the Shelby area are concluded for 2012.

TGGT's capital spending for the second quarter of 2012 was $28 million and the total capital for the first half of 2012 was $97 million. We expect that TGGT will spend approximately $35 million during the second half of 2012. The additional capital spending will be primarily in the Holly area associated with pipeline laterals, permanent treating facilities and well connects.

Financial Data

Our consolidated balance sheets as of June 30, 2012 and December 31, 2011 and consolidated statements of operations for the three and six months ended June 30, 2012 and 2011, and consolidated statements of cash flows for the six months ended June 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 Wednesday, August 1, 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# 94605622. 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 Tuesday, July 31, 2012.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., August 15, 2012. Please call 800-585-8367 and enter conference ID# 94605622 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) June 30, 2012 December 31, 2011
(Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 52,396 $ 31,997
Restricted cash 60,758 155,925
Accounts receivable, net:
Oil and natural gas 49,510 88,518
Joint interest 105,741 170,918
Interest and other 24,098 28,488
Inventory 7,428 8,345
Derivative financial instruments 111,830 164,002
Other 19,676   29,815  
Total current assets 431,437   678,008  
Equity investments 320,214 302,833
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized 592,172 667,342
Proved developed and undeveloped oil and natural gas properties 3,027,501 3,392,146
Accumulated depletion (1,826,196 ) (1,657,165 )
Oil and natural gas properties, net 1,793,477   2,402,323  
Gas gathering assets 136,903 136,203
Accumulated depreciation and amortization (32,433 ) (29,104 )
Gas gathering assets, net 104,470   107,099  
Office, field and other equipment, net 24,217 42,384
Deferred financing costs, net 25,317 29,622
Derivative financial instruments 24,851 11,034
Goodwill 218,256 218,256
Other assets 28   28  
Total assets $ 2,942,267   $ 3,791,587  
EXCO Resources, Inc.
Consolidated balance sheets
   
(in thousands) June 30, 2012 December 31, 2011
(Unaudited)
Liabilities and shareholders’ equity
Current liabilities:
Accounts payable and accrued liabilities $ 98,200 $ 117,968
Revenues and royalties payable 107,421 148,926
Accrued interest payable 17,459 17,973
Current portion of asset retirement obligations 732 732
Income taxes payable
Derivative financial instruments 1,556   1,800  
Total current liabilities 225,368   287,399  
Long-term debt 1,848,389 1,887,828
Deferred income taxes
Derivative financial instruments 35,242
Asset retirement obligations and other long-term liabilities 60,167 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; 217,183,193 shares issued and 216,643,972 shares outstanding at June 30, 2012; 217,245,504 shares issued and 216,706,283 shares outstanding at December 31, 2011 215 215
Additional paid-in capital 3,191,236 3,181,063
Accumulated deficit (2,410,871 ) (1,615,467 )
Treasury stock, at cost; 539,221 shares at June 30, 2012 and December 31, 2011 (7,479 ) (7,479 )
Total shareholders’ equity 773,101   1,558,332  
Total liabilities and shareholders’ equity $ 2,942,267   $ 3,791,587  
EXCO Resources, Inc.
Consolidated statements of operations
(Unaudited)
   
Three Months Ended June 30, Six Months Ended June 30,
(in thousands, except per share data) 2012   2011 2012   2011
Revenues:
Oil and natural gas $ 117,978 $ 206,828 $ 252,826 $ 368,056
Costs and expenses:
Oil and natural gas operating costs 18,863 20,697 41,659 39,742
Production and ad valorem taxes 6,789 6,448 13,982 12,047
Gathering and transportation 25,913 19,504 52,336 36,790
Depreciation, depletion and amortization 87,337 85,412 176,919 153,342
Write-down of oil and natural gas properties 428,801 704,665
Accretion of discount on asset retirement obligations 964 933 1,911 1,790
General and administrative 18,637 23,137 40,142 46,560
Other operating items 6,710   1,669   8,335   4,126  
Total costs and expenses 594,014   157,800   1,039,949   294,397  
Operating income (loss) (476,036 ) 49,028 (787,123 ) 73,659
Other income (expense):
Interest expense (20,369 ) (13,679 ) (37,133 ) (28,495 )
Gain (loss) on derivative financial instruments (15,258 ) 43,273 38,607 46,694
Other income 197 202 440 362
Equity income 15,033   3,538   7,127   12,083  
Total other income (expense) (20,397 ) 33,334   9,041   30,644  
Income (loss) before income taxes (496,433 ) 82,362 (778,082 ) 104,303
Income tax expense        
Net income (loss) $ (496,433 ) $ 82,362   $ (778,082 ) $ 104,303  
Earnings (loss) per common share:
Basic:
Net income (loss) $ (2.32 ) $ 0.39   $ (3.63 ) $ 0.49  
Weighted average common shares outstanding 214,164   213,888   214,154   213,710  
Diluted:
Net income (loss) $ (2.32 ) $ 0.38   $ (3.63 ) $ 0.48  
Weighted average common and common equivalent shares outstanding 214,164   217,513   214,154   217,313  
EXCO Resources, Inc.
Consolidated statement of cash flows
(Unaudited)
 
Six Months Ended June 30,
(in thousands) 2012   2011
Operating Activities:
Net income (loss) $ (778,082 ) $ 104,303
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization 176,919 153,342
Share-based compensation expense 5,455 5,087
Accretion of discount on asset retirement obligations 1,911 1,790
Write-down of oil and natural gas properties 704,665
Income from equity investments (7,127 ) (12,083 )
Non-cash change in fair value of derivatives 73,353 3,458
Deferred income taxes
Amortization of deferred financing costs and discount on the 2018 Notes 6,440 3,747
Effect of changes in:
Accounts receivable 107,693 (48,445 )
Other current assets 4,997 (3,590 )
Accounts payable and other current liabilities (15,756 ) 20,424  
Net cash provided by operating activities 280,468   228,033  
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment (305,969 ) (474,838 )
Property acquisitions (2,748 ) (722,032 )
Equity method investments (10,254 ) (10,279 )
Proceeds from disposition of property and equipment 17,000 410,870
Restricted cash 95,167 12,502
Net changes in advances (to) from Appalachia JV 5,193 (1,309 )
Distributions from equity method investments 125,000
Deposit on acquisitions 464,151
Other   (1,250 )
Net cash used in investing activities (201,611 ) (197,185 )
Financing Activities:
Borrowings under the EXCO Resources Credit Agreement 53,000 380,000
Repayments under the EXCO Resources Credit Agreement (93,000 ) (377,500 )
Proceeds from issuance of common stock 297 11,063
Payment of common stock dividends (17,132 ) (17,106 )
Deferred financing costs and other (1,623 ) (6,348 )
Net cash used in financing activities (58,458 ) (9,891 )
Net increase in cash 20,399 20,957
Cash at beginning of period 31,997   44,229  
Cash at end of period $ 52,396   $ 65,186  
Supplemental Cash Flow Information:
Cash interest payments $ 42,454   $ 37,564  
Income tax payments $   $ 1,458  
Supplemental non-cash investing and financing activities:
Capitalized stock option compensation $ 3,894   $ 2,800  
Capitalized interest $ 12,525   $ 15,748  
Issuance of common stock for director services $ 527   $ 34  
Accrued restricted stock dividends $ 190   $  
EXCO Resources, Inc.
Consolidated EBITDA
And Adjusted EBITDA reconciliations and statement of cash flow data
(Unaudited)
   
Three months ended Six months ended
June 30, June 30,
(in thousands) 2012   2011 2012   2011
Net income (loss) $ (496,433 ) $ 82,362 $ (778,082 ) $ 104,303
Interest expense 20,369 13,679 37,133 28,495
Income tax expense
Depreciation, depletion and amortization 87,337   85,412   176,919   153,342  
EBITDA(1) (388,727 ) 181,453 (564,030 ) 286,140
Accretion of discount on asset retirement obligations 964 933 1,911 1,790
Non-cash write down of oil and natural gas properties 428,801 704,665
Non-recurring other operating items 6,673 2,980 8,625 5,955
Equity income (15,033 ) (3,538 ) (7,127 ) (12,083 )
Non-cash change in fair value of derivative financial instruments 77,073 (20,056 ) 73,353 3,458
Stock based compensation expense 2,591   2,419   5,455   5,087  
Adjusted EBITDA (1) $ 112,342 $ 164,191 $ 222,852 $ 290,347
Interest expense (20,369 ) (13,679 ) (37,133 ) (28,495 )
Income tax expense

Amortization of deferred financing costs and discount on the 2018 Notes
4,690 1,800 6,440 3,747
Deferred income taxes
Non-recurring other operating items (6,673 ) (2,980 ) (8,625 ) (5,955 )
Changes in working capital 45,355   (372 ) 96,934   (31,611 )
Net cash provided by operating activities $ 135,345   $ 148,960   $ 280,468   $ 228,033  
  Three months ended   Six months ended
June 30, June 30,
(in thousands) 2012   2011 2012   2011
Statement of cash flow data (unaudited):
Cash flow provided by (used in):
Operating activities $ 135,345 $ 148,960 $ 280,468 $ 228,033
Investing activities (33,723 ) (343,646 ) (201,611 ) (197,185 )
Financing activities (79,797 ) 251,344 (58,458 ) (9,891 )
Other financial and operating data:
EBITDA(1) (388,727 ) 181,453 (564,030 ) 286,140
Adjusted EBITDA(1) 112,342 164,191 222,852 290,347
 

(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 Six Months Ended
June 30, June 30,
(in thousands) 2012   2011 2012   2011
 
Equity Income (loss) $ 15,033 $ 3,538 $ 7,127 $ 12,083
Amortization of the difference in the historical basis of our contribution to TGGT (402 ) (402 ) (804 ) (804 )
Equity loss of other investments 1,715   371   2,594   630  
EXCO's share of TGGT net income (loss) 16,346 3,507 8,917 11,909
BG Group's share of TGGT net income 16,346   3,507   8,917   11,909  
TGGT net income (loss) 32,692 7,014 17,834 23,818
Interest expense 2,683 2,324 6,557 3,867
Margin tax expense 30 384 268 719
Depreciation and amortization 6,942   6,328   14,823   12,232  
TGGT EBITDA(1) 42,347 16,050 39,482 40,636
Asset impairments and non-recurring other operating items   13,460   37,598   13,460  
TGGT Adjusted EBITDA(1) $ 42,347   $ 29,510   $ 77,080   $ 54,096  
EXCO's share of TGGT Adjusted EBITDA (2) $ 21,174   $ 14,755   $ 38,540   $ 27,048  
 

(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 Six Months Ended
June 30, June 30,
(in thousands) 2012   2011 2012   2011
Net income (loss), GAAP $ 32,692 $ 7,014 $ 17,834 $ 23,818
Adjustments:
Loss on asset disposal 1,399
Asset impairment 13,460 35,343 13,460
Other non-cash items 856
Income taxes on above adjustments      
Total adjustments, net of taxes   13,460   37,598   13,460
Adjusted net income $ 32,692   $ 20,474   $ 55,432   $ 37,278
 
EXCO's 50% share of TGGT's adjusted net income (1) $ 16,346   $ 10,237   $ 27,716   $ 18,639
 

(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 Six months ended
June 30, % June 30, %
  2012   2011 Change 2012   2011 Change
Production:
Oil (Mbbls) 182 178 2 % 374 371 1 %
Natural gas liquids (Mbbls) 131 123 7 % 253 248 2 %
Natural gas (Mmcf) 48,162 44,080 9 % 95,154 79,217 20 %
Total production (Mmcfe) (1) 50,040 45,886 9 % 98,916 82,931 19 %
Average daily production (Mmcfe) 550 504 9 % 543 458 19 %
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl) $ 86.38 $ 99.16 (13 )% $ 91.90 $ 94.40 (3 )%
Natural gas liquids (per Bbl) 40.15 60.47 (34 )% 46.30 56.88 (19 )%
Natural gas (per Mcf) 2.01 4.12 (51 )% 2.17 4.03 (46 )%
Natural gas equivalent (per Mcfe) 2.36 4.51 (48 )% 2.56 4.44 (42 )%
Costs and expenses (per Mcfe):
Oil and natural gas operating costs $ 0.38 $ 0.45 (16 )% $ 0.42 $ 0.48 (13 )%
Production and ad valorem taxes 0.14 0.14 % 0.14 0.15 (7 )%
Gathering and transportation 0.52 0.43 21 % 0.53 0.44 20 %
Depletion 1.67 1.76 (5 )% 1.71 1.74 (2 )%
Depreciation and amortization 0.08 0.10 (20 )% 0.08 0.11 (27 )%
General and administrative 0.37 0.50 (26 )% 0.41 0.56 (27 )%
 

(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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