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Press release from Business Wire

EXCO Resources, Inc. Reports First Quarter 2013 Results

Tuesday, April 30, 2013

EXCO Resources, Inc. Reports First Quarter 2013 Results

16:03 EDT Tuesday, April 30, 2013

DALLAS (Business Wire) -- EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced first quarter results for 2013.

  • Adjusted net income, a non-GAAP measure adjusting for gains from asset sales, non-cash gains or losses from derivative financial instruments (derivatives), non-cash ceiling test write-downs and other items typically not included by securities analysts in published estimates, was $0.13 per diluted share for the first quarter 2013 compared to $0.03 per diluted share for the first quarter 2012.
  • Adjusted earnings before interest, taxes, depreciation, depletion and amortization, gains on asset sales, ceiling test write-downs and other non-cash income and expense items (adjusted EBITDA, a non-GAAP measure) for the first quarter 2013 were $96 million compared with $111 million in the first quarter 2012.
  • GAAP results were net income of $158 million, or $0.74 per diluted share, for the first quarter 2013 compared with a net loss of $282 million, or $1.32 per diluted share, for the first quarter 2012. The first quarter 2013 includes a $187 million gain from the contribution of 74.5% of our interests in certain conventional properties to our partnership with Harbinger Group Inc. (HGI). The first quarter 2012 net loss was primarily due to a $276 million non-cash ceiling test write-down of oil and natural gas properties.
  • Oil, natural gas and natural gas liquids (NGL) production was 41 Bcfe, or 452 Mmcfe per day, for the first quarter 2013 compared with 49 Bcfe, or 537 Mmcfe per day in the first quarter 2012. The decreases in production reflect the impact of the properties contributed to the partnership with HGI and our reduced drilling program initiated in 2012. First quarter 2013 production from our Haynesville/Bossier shale was 337 Mmcf per day compared with 390 Mmcf per day in the first quarter 2012. First quarter 2013 production in our Appalachia region was 56 Mmcfe per day, a 37% increase from the first quarter 2012. The increase reflects drilling in the Marcellus shale and completion activities which resulted in 41 additional wells coming on-line subsequent to first quarter 2012.
  • Oil, natural gas and NGL revenues, before cash settlements on derivatives, for the first quarter 2013 were $138 million compared with first quarter 2012 revenues of $135 million. Our average sales price per Mcfe increased to $3.40 per Mcfe for the first quarter 2013 from $2.76 per Mcfe for the first quarter 2012. When the impacts of cash settlements from derivatives are considered, oil, natural gas and NGL revenues were $155 million for the first quarter 2013, compared with $185 million in the first quarter 2012.
  • Our direct operating costs were $0.33 per Mcfe for the first quarter 2013 compared with $0.47 per Mcfe for the first quarter 2012. We continue taking significant steps in reducing our operating costs in all operating areas. In addition, our first quarter 2013 operating costs per Mcfe were favorably impacted by the contribution of certain conventional properties to the partnership with HGI. The conventional assets have higher operating costs than our horizontal wells.
  • TGGT's average throughput was approximately 1.4 Bcf per day during the first quarter 2013, compared with 1.5 Bcf per day during the fourth quarter 2012 and 1.5 Bcf per day in the first quarter 2012. Our 50% share of TGGT's adjusted EBITDA in the first quarter 2013 was $18 million compared with $17 million in the first quarter 2012.
  • On February 14, 2013, we formed a partnership with HGI. We contributed our conventional non-shale assets in East Texas and North Louisiana and our shallow Canyon Sand and other assets in the Permian Basin of West Texas to the partnership in exchange for net proceeds of $573 million, after customary preliminary purchase price adjustments and a 25.5% economic interest in the partnership. HGI's economic interest in the partnership is 74.5%. We report our 25.5% interest in the partnership using proportional consolidation. The primary strategy of the partnership is to acquire conventional producing oil and natural gas properties to enhance asset value and cash flow. Immediately following the closing, the partnership entered into an agreement to purchase certain shallow conventional assets from BG Group, plc (BG Group) for $131 million, after customary preliminary purchase price adjustments. This acquisition represented incremental working interest in properties operated by the partnership. The following table presents selected pro forma operating and financial information for the three months ended March 31, 2013 and 2012 as if these transactions occurred on January 1, 2012:
    Three months ended March 31, 2013       Three months ended March 31, 2012
(dollars in thousands, except per unit rate)

Historical
EXCO

   

Pro forma
adjustments
(1)

   

Pro forma
EXCO

Historical
EXCO

   

Pro forma
adjustments
(1)

   

Pro forma
EXCO

Production:
Total production (Mmcfe) 40,697 (2,705 ) 37,992 48,876 (6,606 ) 42,270
Average production (Mmcfe/d) 452 (30 ) 422 537 (73 ) 464
Revenues:
Revenues, excluding derivatives $ 138,223 $ (12,657 ) $ 125,566

$

134,848 $ (30,758 ) $ 104,090
Average realized price ($/Mcfe) 3.40 4.68 3.31 2.76 4.66 2.46
Expenses:
Direct operating costs $ 13,617 $ (3,489 ) $ 10,128

$

22,796

$ (8,420 ) $ 14,376
Per Mcfe 0.33 1.29 0.27 0.47 1.27 0.34
Production and ad valorem taxes 5,248 (1,545 ) 3,703 7,193 (3,531 ) 3,662
Per Mcfe 0.13 0.57 0.10 0.15 0.53 0.09
Gathering and transportation 24,476 (782 ) 23,694 26,423 (2,502 ) 23,921
Per Mcfe 0.60 0.29 0.62 0.54 0.38 0.57
Excess of revenues over operating expenses $ 94,882 $ (6,841 ) $ 88,041 $ 78,436 $ (16,305 ) $ 62,131
(1)   The 2013 pro forma adjustments reflect the contribution of our interest in certain properties from January 1, 2013 to February 14, 2013 and the acquisition of certain shallow conventional assets from BG Group from January 1, 2013 to March 31, 2013. The 2012 pro forma adjustments reflect the impact of these transactions from January 1, 2012 to March 31, 2012.
 
  • We improved our liquidity by using the proceeds received upon formation of the partnership with HGI to reduce outstanding borrowings under our credit agreement. As a result of this transaction, our borrowing base under our credit agreement was reduced to $900 million. In addition, we utilized cash flows from operations and other divestitures to reduce outstanding borrowings under our credit agreement by an additional $40 million during the three months ended March 31, 2013.

Douglas H. Miller, EXCO's Chief Executive Officer, commented, “We are pleased with the positive financial results achieved in the first quarter through a continued focus on reducing expenses. Our operations team also continues to make drilling cost reductions in the Haynesville and Marcellus, and we are encouraged by the recent increase in natural gas prices.

“The Harbinger partnership transaction completed in February establishes a strong partnership that will enhance the long term value of EXCO while giving us flexibility and liquidity in the short term. We are excited to work with Harbinger Group Inc. to make strategic acquisitions to grow and develop this partnership.

“With our new senior leadership team in place, we will continue to actively evaluate acquisition opportunities and develop our properties within cash flow to grow the value of the Company. Regardless of commodity prices in 2013, we expect to continue to preserve liquidity, focus on cost controls and deliver stable cash flows.”

Adjusted 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
March 31, 2013       March 31, 2012
(in thousands, except per share amounts) Amount     Per share Amount     Per share
Net income (loss), GAAP $ 158,120 $ (281,649 )
Adjustments:
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes 60,232 (3,720 )
Non-cash write down of oil and natural gas properties, before taxes 10,707 275,864
Adjustments included in equity (income) loss (286 ) 18,799
(Gain) loss on divestitures and other operating items (184,386 ) 1,952
Deferred finance cost amortization acceleration 3,535
Income taxes on above adjustments (1) 44,079 (117,158 )
Adjustment to deferred tax asset valuation allowance (2)   (63,248 )   112,660  
Total adjustments, net of taxes   (129,367 )   288,397  
Adjusted net income $ 28,753   $ 6,748  
Net income (loss), GAAP (3) $ 158,120 $ 0.74 $ (281,649 ) $ (1.32 )
Adjustments shown above (3) (129,367 ) (0.60 ) 288,397 1.35
Dilution attributable to share-based payments (4)       (0.01 )        
Adjusted net income $ 28,753   $ 0.13   $ 6,748   $ 0.03  
 
Common stock and equivalents used for earnings per share (EPS):
Weighted average common shares outstanding 214,784 214,145
Dilutive stock options 5 451
Dilutive restricted shares   72      
Shares used to compute diluted EPS for adjusted net income   214,861     214,596  
(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.
 

Cash flow

Our cash flow from operations before changes in working capital was $81 million for the first quarter 2013. We use our cash flow and available borrowing capacity in our credit agreement to fund our drilling and development programs and acquire producing properties.

    Three Months Ended
March 31,
(in thousands) 2013     2012
Cash flow from operations, GAAP $ 43,214 $ 145,123
Net change in working capital 34,990 (51,579 )
Non-recurring other operating items   2,652   1,952  
Cash flow from operations before changes in working capital and non-recurring other operating items, non-GAAP measure (1) $ 80,856 $ 95,496  
(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. 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. Non-recurring other operating items have been excluded as they do not reflect our on-going operating activities.
 

Operations activity and outlook

We spent $59 million on development and exploitation activities, drilling and completing 28 gross (14.2 net) operated wells in the first quarter 2013. In addition, we participated in 2 gross (0.1 net) wells operated by others (OBO) during the first quarter 2013. We had an overall drilling success rate of 100% for the first quarter 2013. We spent $77 million on development and exploitation activities, drilling and completing 43 gross (18.9 net) operated wells in the fourth quarter 2012. In addition, we participated in 1 gross (0.2 net) well operated by others (OBO) during the fourth quarter 2012.

Our actual capital expenditures for the first quarter 2013 and our full year 2013 capital budget are presented in the following table:

(in thousands)    

Three Months Ended
March 31, 2013

   

April - December 2013
Forecast

   

Full Year 2013
Forecast

Capital expenditures (1):
Development capital $ 58,715 $ 161,285 $ 220,000
Gas gathering and water pipelines
Lease acquisitions and seismic 14,000 14,000
Capitalized interest 5,038 9,962 15,000
Corporate and other   4,596   19,404   24,000
Total $ 68,349 $ 204,651 $ 273,000
(1)   Excludes capital expenditures related to our partnership with HGI.
 

Our 2013 capital budget, as approved by our Board of Directors, is highly dependent upon natural gas prices and is therefore subject to change. Further, our renewed focus on acquisitions of producing properties and our interest in obtaining outside participation in certain of our drilling activities and acquisitions of drilling locations could have an impact on the 2013 approved capital budget. We will update our capital spending plans on a quarterly basis during the year.

Haynesville/Bossier Shale

Our horizontal Haynesville shale development program is a significant asset for EXCO and continues to yield strong results. At the end of the first quarter 2013, our Haynesville/Bossier shale operated production was 1,067 Mmcf per day gross (316 Mmcf per day net) and with the addition of production from our OBO wells, we had 338 Mmcf per day of total net Haynesville/Bossier shale production. We currently have three operated rigs drilling in the play. While our current plan is to maintain three rigs through 2013, we will continue to assess product pricing and project economics to make further decisions on our drilling activity. Our development drilling program for the first quarter 2013 was focused in DeSoto Parish, Louisiana where we continued our 80-acre spacing manufacturing program. We currently have 37 units fully developed in the Haynesville in DeSoto Parish. We completed and turned to sales 19 gross (7.8 net) operated Haynesville horizontal wells in the quarter. We utilized an average of three operated rigs and spud eight operated horizontal wells during the quarter. We participated in two OBO wells during the quarter and currently have one OBO rig drilling. In total, we have 396 operated horizontal wells and 179 OBO horizontal wells flowing to sales.

During 2013, we plan to drill 26 gross (15.5 net) operated wells with a three rig program. We plan to complete and turn to sales a total of 42 gross wells (22.1 net), including completions carried into 2013 from wells drilled in late 2012.

The average initial production rate from the 19 operated Haynesville horizontal wells completed and turned to sales in the first quarter 2013 in DeSoto Parish was 13.7 Mmcf per day with an average 7,811 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.

Our cost reduction and efficiency program is delivering positive results. We continue to see improvements in drilling times, stimulation costs and overall capital efficiency. Our current DeSoto Parish well costs are averaging approximately $7.8 million per well. The largest factors in our cost reduction efforts to date are fracture stimulation market conditions, fracture stimulation design changes, modified tubing program, reduced drilling times and overall improved management of all rental items. Our operations control room in our Dallas headquarters plays a significant role in our well surveillance and gas scheduling process. We have reduced our overall production downtime in the Haynesville to approximately 4.9% through better coordination and scheduling in all aspects of our field activities. 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 operated Marcellus shale production at the end of the first quarter 2013 was 181 Mmcf per day (48.3 Mmcf per day net). This represents a 15% increase since year end 2012. Our focus through 2013 is to complete and turn to sales our remaining drilled well inventory while reducing the size of our appraisal drilling program due to low product pricing. In the first quarter 2013, we spud one Marcellus appraisal well in Northeast Pennsylvania and completed five gross operated (2.5 net) Marcellus wells in Central and Northeast Pennsylvania. We turned to sales eight Marcellus wells in late 2012 in West Lycoming County Pennsylvania that resulted in some of our highest well performances to date as the IP rates ranged from 7.1 to 11.8 Mmcf per day with an average of 8.9 Mmcf per day per well. During the remainder of 2013, we plan to turn to sales an additional 13 Marcellus wells (nine in our Central Pennsylvania area and four in the East Lycoming County area). Our development planning for 2014 is underway and will be a combination of development drilling in our highest rate of return areas and selective appraisal drilling to delineate more of our acreage base.

In addition to the Marcellus shale production in Appalachia, we averaged 32 gross (13.2 net) operated Mmcf per day of conventional production in the region.

Partnership with HGI

The following discussion of operating results, capital expenditures and planned operations addresses our partnership with HGI. We contributed the conventional Permian and East Texas/North Louisiana assets to the partnership with HGI on February 14, 2013. On March 5, 2013 the partnership acquired additional oil and natural gas assets, including and above the Cotton Valley formation in the Danville, Waskom, and Holly fields in East Texas and North Louisiana from an affiliate of BG Group. The capital budget for the partnership with HGI for 2013 is approximately $40.0 million, which is primarily focused on development of its Permian Basin assets in West Texas and recompletion projects in North Louisiana.

Permian

During the first quarter 2013, 8 gross (7.8 net) wells were drilled and completed in the Sugg Ranch area with 100% drilling success. Economics for this drilling activity typically have high rates-of-return driven by oil and NGL content. The partnership with HGI expects to run one operated rig and drill and complete 36 gross (34.9 net) wells at Sugg Ranch in 2013. At the end of the first quarter 2013, production from the 445 partnership wells averaged approximately 3,700 barrels per day of net oil equivalents. This average production rate consisted of 1,360 net barrels of oil, 6,000 net Mcf of natural gas, and 1,330 net barrels of natural gas liquids per day.

East Texas/North Louisiana

The Vernon Field in Jackson Parish, Louisiana is the most significant producing field in this group of assets. At the end of the first quarter 2013, production from the operated partnership wells averaged approximately 45 Mmcfe per day of net natural gas from the lower Cotton Valley and Bossier Sand formations. With current low commodity prices, the primary focus in the Vernon Field is to minimize operating expense while maintaining production.

The partnership with HGI has additional acreage and production in Caddo and DeSoto Parishes, Louisiana, primarily in four fields - Holly, Kingston, Caspiana and Longwood. In addition, the partnership with HGI has acreage and production in Harrison, Panola and Gregg Counties in Texas, primarily across three fields - Carthage, Waskom, and Danville. Production from these areas is primarily from Cotton Valley, Travis Peak and Hosston sands. At the end of the first quarter 2013, production from the operated partnership wells in these fields averaged approximately 37 Mmcfe per day of net natural gas. Due to low commodity prices, the partnership with HGI is not actively drilling in these fields. Capital spending during the first quarter 2013 was focused on maintaining a strong emphasis on base production performance. The partnership typically runs multiple service rigs replacing tubing, changing pumps, cleaning out fill and implementing general repairs to maintain optimum production levels. During the remainder of the year, the partnership will initiate recompletions in 9 wells in the Holly field targeting Cotton Valley and Hosston sands. In East Texas/North Louisiana, the partnership with HGI currently has 906 wells flowing to sales with a total gross operated production rate of approximately 119 Mmcfe per day (82 Mmcfe per day net).

TGGT

Our jointly held midstream company, TGGT, had total throughput which averaged approximately 1.4 Bcf per day during the first quarter of 2013. TGGT's adjusted EBITDA was $37 million for the first quarter of 2013, which was a 6% increase over TGGT's adjusted EBITDA of $35 million for the first quarter of 2012. Through an effective asset optimization program, TGGT continues to significantly reduce its operating expenses, which were 21% less in the first quarter of 2013 than the fourth quarter of 2012.

TGGT's capital spending for the first quarter of 2013 was $7 million, which was 61% lower than the $18 million spent in the fourth quarter of 2012. Capital spending has transitioned from major facility and pipeline projects to primarily installation of field infrastructure pipelines to support producer drilling activity in North Louisiana and East Texas.

Financial Data

Our consolidated balance sheets as of March 31, 2013 and December 31, 2012, consolidated statements of operations for the three months ended March 31, 2013 and 2012 and consolidated statements of cash flows for the three months ended March 31, 2013 and 2012, 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, May 1, 2013 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#32095842. 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, April 30, 2013.

A digital recording will be available starting two hours after the completion of the conference call until 11:59 p.m., May 15, 2013. Please call (800) 585-8367 and enter conference ID#32095842 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 and Chief Executive Officer, Douglas H. Miller, or its President and Chief Operating Officer, Harold L. Hickey, or its Executive Vice President and Chief Financial Officer, Mark F. Mulhern, 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, 2012, filed with the Securities and Exchange Commission, or the SEC, on February 21, 2013 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, or the EXCO Resources 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.

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 filings with the commission. 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, 2012, which is available on our website at www.excoresources.com under the Investor Relations tab.

       
EXCO Resources, Inc.
Consolidated Balance Sheets
 
(in thousands)

March 31,
2013

December 31,
2012

(Unaudited)
Assets
Current assets:
Cash and cash equivalents $ 26,646 $ 45,644
Restricted cash 53,292 70,085
Accounts receivable, net:
Oil and natural gas 70,687 84,348
Joint interest 71,690 69,446
Other 18,230 15,053
Inventory 4,218 5,705
Derivative financial instruments 10,653 49,500
Other   18,647     22,085  
Total current assets   274,063     361,866  
Equity investments 359,739 347,008
Oil and natural gas properties (full cost accounting method):
Unproved oil and natural gas properties and development costs not being amortized 389,998 470,043
Proved developed and undeveloped oil and natural gas properties 2,618,292 2,715,767
Accumulated depletion   (1,984,556 )   (1,945,565 )
Oil and natural gas properties, net   1,023,734     1,240,245  
Gas gathering assets 33,810 130,830
Accumulated depreciation and amortization   (9,236 )   (34,364 )
Gas gathering assets, net   24,574     96,466  
Office, field and other equipment, net 19,156 20,725
Deferred financing costs, net 19,257 22,584
Derivative financial instruments 6,440 16,554
Goodwill 163,155 218,256
Other assets   28     28  
Total assets $ 1,890,146   $ 2,323,732  
 
       
EXCO Resources, Inc.
Consolidated Balance Sheets
 
(in thousands, except per share and share data)

March 31,
2013

December 31,
2012

(Unaudited)
Liabilities and shareholders' equity
Current liabilities:
Accounts payable and accrued liabilities $ 59,125 $ 83,240
Revenues and royalties payable 112,710 134,066
Accrued interest payable 3,089 17,029
Current portion of asset retirement obligations 395 1,200
Income taxes payable
Derivative financial instruments   17,639     2,396  
Total current liabilities   192,958     237,931  
Long-term debt 1,331,376 1,848,972
Deferred income taxes
Derivative financial instruments 23,783 26,369
Asset retirement obligations and other long-term liabilities 42,085 61,067
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; 218,049,105 shares issued and 217,509,884 shares outstanding at March 31, 2013; 218,126,071 shares issued and 217,586,850 shares outstanding at December 31, 2012

215 215
Additional paid-in capital 3,203,364 3,200,067
Accumulated deficit (2,896,156 ) (3,043,410 )
Treasury stock, at cost; 539,221 shares at March 31, 2013 and December 31, 2012   (7,479 )   (7,479 )
Total shareholders' equity   299,944     149,393  
Total liabilities and shareholders' equity $ 1,890,146   $ 2,323,732  
 
   
EXCO Resources, Inc.
Consolidated Statements of Operations
(Unaudited)
 
Three Months Ended March 31,
(in thousands, except per share data) 2013     2012
Revenues:
Oil and natural gas $ 138,223 $ 134,848
Costs and expenses:
Oil and natural gas operating costs 13,617 22,796
Production and ad valorem taxes 5,248 7,193
Gathering and transportation 24,476 26,423
Depletion, depreciation and amortization 41,308 89,582
Write-down of oil and natural gas properties 10,707 275,864
Accretion of discount on asset retirement obligations 690 947
General and administrative 17,984 21,505
(Gain) loss on divestitures and other operating items   (184,882 )   1,625  
Total costs and expenses   (70,852 )   445,935  
Operating income (loss) 209,075 (311,087 )
Other income (expense):
Interest expense (20,192 ) (16,764 )
Gain (loss) on derivative financial instruments (43,514 ) 53,865
Other income 88 243
Equity income (loss)   12,663     (7,906 )
Total other income (expense)   (50,955 )   29,438  
Income (loss) before income taxes 158,120 (281,649 )
Income tax expense        
Net income (loss) $ 158,120   $ (281,649 )
Earnings (loss) per common share:
Basic:
Net income (loss) $ 0.74   $ (1.32 )
Weighted average common shares outstanding   214,784     214,145  
Diluted:
Net income (loss) $ 0.74   $ (1.32 )
Weighted average common and common equivalent shares outstanding   214,861     214,145  
 
   
EXCO Resources, Inc.
Consolidated Statements of Cash Flows
(Unaudited)
 
Three Months Ended March 31,
(in thousands) 2013     2012
Operating Activities:
Net income (loss) $ 158,120 $ (281,649 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization 41,308 89,582
Share-based compensation expense 1,735 2,864
Accretion of discount on asset retirement obligations 690 947
Write-down of oil and natural gas properties 10,707 275,864
(Income) loss from equity investments (12,663 ) 7,906
Non-cash change in fair value of derivatives 60,232 (3,720 )
Deferred income taxes
Amortization of deferred financing costs and discount on the 2018 Notes 5,113 1,750
Gain on divestitures (187,038 )
Effect of changes in:
Accounts receivable 8,518 78,796
Other current assets (1,628 ) 1,871
Accounts payable and other current liabilities   (41,880 )   (29,088 )
Net cash provided by operating activities   43,214     145,123  
Investing Activities:
Additions to oil and natural gas properties, gathering systems and equipment (72,911 ) (169,756 )
Property acquisitions (33,390 ) (1,402 )
Equity method investments (68 ) (137 )
Proceeds from disposition of property and equipment 611,203 981
Restricted cash 16,793 (8,117 )
Net changes in advances from Appalachia JV   3,633     10,543  
Net cash provided by (used in) investing activities   525,260     (167,888 )
Financing Activities:
Borrowings under credit agreements 46,757 53,000
Repayments under credit agreements (623,266 ) (23,000 )
Proceeds from issuance of common stock 22 2
Payment of common stock dividends (10,739 ) (8,663 )
Deferred financing costs and other   (246 )    
Net cash provided by (used in) financing activities   (587,472 )   21,339  
Net decrease in cash (18,998 ) (1,426 )
Cash at beginning of period   45,644     31,997  
Cash at end of period $ 26,646   $ 30,571  
 
 
Supplemental Cash Flow Information:
Cash interest payments $ 33,624   $ 34,883  
Income tax payments $   $  
Supplemental non-cash investing and financing activities:
Capitalized share-based compensation $ 1,527   $ 1,931  
Capitalized interest $ 5,079   $ 6,302  
Issuance of common stock for director services $ 13   $ 17  
Accrued restricted stock dividends $ 127   $ 97  
Debt assumed upon formation of EXCO/HGI Partnership, net $ 58,613   $  
 
   
EXCO Resources, Inc.
Consolidated EBITDA
And Adjusted EBITDA Reconciliations and Statement of Cash Flow Data
(Unaudited)
 
Three Months Ended
March 31,
(in thousands) 2013     2012
Net income (loss) $ 158,120 $ (281,649 )
Interest expense 20,192 16,764
Income tax expense
Depletion, depreciation and amortization   41,308     89,582  
EBITDA(1) 219,620 (175,303 )
Accretion of discount on asset retirement obligations 690 947
Non-cash write down of oil and natural gas properties 10,707 275,864
(Gain) on divestitures and other non-recurring operating items (184,386 ) 1,952
Equity (income) loss (12,663 ) 7,906
Non-cash change in fair value of derivative financial instruments 60,232 (3,720 )
Share based compensation expense   1,735     2,864  
Adjusted EBITDA (1) $ 95,935 $ 110,510
Interest expense (20,192 ) (16,764 )
Income tax expense
Amortization of deferred financing costs and discount on the 2018 Notes 5,113 1,750
Non-recurring other operating items (2,652 ) (1,952 )
Changes in working capital   (34,990 )   51,579  
Net cash provided by operating activities $ 43,214   $ 145,123  
 
   
Three Months Ended
March 31,
(in thousands) 2013     2012
Statement of cash flow data:
Cash flow provided by (used in):
Operating activities $ 43,214 $ 145,123
Investing activities 525,260 (167,888 )
Financing activities (587,472 ) 21,339
Other financial and operating data:

EBITDA (1)

219,620 (175,303 )

Adjusted EBITDA (1)

95,935 110,510
(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
March 31,
(in thousands) 2013     2012
 
Equity income (loss) $ 12,663 $ (7,906 )
Amortization of the difference in the historical basis of our contribution to TGGT (402 ) (402 )
Equity loss of other investments   190     879  
EXCO's share of TGGT net income (loss) 12,451 (7,429 )
BG Group's share of TGGT net income (loss)   12,451     (7,429 )
TGGT net income (loss) 24,902 (14,858 )
Interest expense 3,340 3,874
Margin tax expense 110 238
Depreciation and amortization   8,758     7,881  

TGGT EBITDA (1)

37,110 (2,865 )
Asset impairments and non-recurring other operating items   (571 )   37,598  

TGGT Adjusted EBITDA (1)

$ 36,539   $ 34,733  
EXCO's share of TGGT Adjusted EBITDA (2) $ 18,270   $ 17,367  
(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
March 31,
(in thousands) 2013     2012
Net income (loss), GAAP $ 24,902 $ (14,858 )
Adjustments:
Loss on asset disposal 190 1,399
Asset impairment, net of insurance recoveries 264 35,343
Other non-cash items   (1,025 )   856  
Total adjustments   (571 )   37,598  
Adjusted net income $ 24,331   $ 22,740  
 
EXCO's 50% share of TGGT's adjusted net income (1) $ 12,166   $ 11,370  
(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
March 31, %
  2013     2012 Change
Production:
Oil (Mbbls) 102 192 (47 )%
Natural gas liquids (Mbbls) 82 122 (33 )%
Natural gas (Mmcf) 39,593 46,992 (16 )%
Total production (Mmcfe) (1) 40,697 48,876 (17 )%
Average daily production (Mmcfe) 452 537 (16 )%
Average sales price (before cash settlements of derivative financial instruments):
Oil (per Bbl) $ 81.71 $ 97.14 (16 )%
Natural gas liquids (per Bbl) 37.72 52.90 (29 )%
Natural gas (per Mcf) 3.20 2.34 37 %
Natural gas equivalent (per Mcfe) 3.40 2.76 23 %
Costs and expenses (per Mcfe):
Oil and natural gas operating costs $ 0.33 $ 0.47 (30 )%
Production and ad valorem taxes 0.13 0.15 (13 )%
Gathering and transportation 0.60 0.54 11 %
Depletion 0.96 1.75 (45 )%
Depreciation and amortization 0.06 0.08 (25 )%
General and administrative 0.44 0.44 %
(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.

EXCO Resources, Inc.
Douglas H. Miller, 214-368-2084
Chairman and Chief Executive Officer
or
Harold L. Hickey, 214-368-2084
President and Chief Operating Officer
or
Mark F. Mulhern, 214-368-2084
Executive Vice President and Chief Financial Officer

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