EXCO Resources, Inc. Reports Third Quarter 2012 Results

EXCO Resources, Inc. Reports Third Quarter 2012 Results

DALLAS--(BUSINESS WIRE)-- EXCO Resources, Inc. (NYS: 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, 2011September 30, 2012  September 30, 2011
(in thousands, except per share amounts)Amount  












Net income (loss), GAAP$(346,174)$84,945$(1,124,256)$189,248
Non-cash mark-to-market (gains) losses on derivative financial instruments, before taxes70,986(51,346)144,339(47,888)
Non-cash write down of oil and natural gas properties, before taxes318,0441,022,709
Adjustments included in equity income2,88421,683
Non-recurring other operating items1,10321,5879,72827,542
Deferred finance cost amortization acceleration3,000
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 taxes374,280 (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)374,2801.75(51,833)(0.24)1,170,5775.47(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 outstanding214,301214,068214,204213,831
Dilutive stock options 2,246  3,336 
Shares used to compute diluted EPS for adjusted net income214,301 216,314 214,204 217,167 


The assumed income tax rate is 40% for all periods.


Deferred tax valuation allowance has been adjusted to reflect the assumed income tax rate of 40% for all periods.


Per share amounts are based on weighted average number of common shares outstanding.


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 EndedNine Months Ended
September 30,September 30,
(in thousands)2012  20112012  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


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 ActualsQ2 ActualsQ3 Actuals

October -




Full Year


Capital expenditures:
Development capital$141,771$97,107$87,786$78,336$405,000
Gas gathering and water pipelines5331633091,9953,000
Lease acquisitions and seismic (1)5,5704,125(595)2,90012,000
Capitalized interest6,3026,2235,9675,50824,000
Corporate and other7,975 6,053 5,202 6,770 26,000
Total$162,151 $113,671 $98,669 $95,509 $470,000


 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 w

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