EXCO Resources, Inc. (NYSE: XCO) (“EXCO”) today announced third quarter results for 2011.
- Adjusted net earnings, a non-GAAP measure adjusting for non-cash gains and losses from derivative financial instruments (derivatives), gains on divestitures, asset impairments, costs incurred in connection with our special committee’s review of strategic alternatives and items typically not included by securities analysts in published estimates, were $0.15 per share for the third quarter 2011 compared to $0.18 per share for the second quarter 2011 and $0.16 per share for the third quarter 2010.
- GAAP results were net income of $0.39 per diluted share for the third quarter 2011 compared with net income of $0.38 per diluted share for the second quarter 2011. Net income was $0.30 per diluted share for the third quarter 2010.
- Oil and natural gas production was 50 Bcfe, or 540 Mmcfe per day, for the third quarter 2011 compared with 46 Bcfe, or 500 Mmcfe per day, in the second quarter 2011. Production was 29 Bcfe, or 320 Mmcfe per day, in the third quarter 2010. The increase in the year-over-year quarterly production is primarily attributable to increased production volumes in our Haynesville/Bossier shale play, where third quarter 2011 volumes were 37 Bcfe, or 401 Mmcfe per day, compared with 16 Bcfe, or 173 Mmcfe per day, in the third quarter 2010, an increase of 132%. The increased production during the third quarter was reduced by approximately 44 Mmcf per day as a result of a May 28, 2011 incident at a TGGT treating facility which resulted in curtailment of certain North Louisiana production volumes. We expect this level of curtailment of certain volumes to continue through the end of the fourth quarter 2011.
- Oil and natural gas revenues for the third quarter 2011 were $207 million, unchanged from the second quarter 2011. The third quarter 2010 oil and natural gas revenues were $131 million. The higher year-over-year revenues reflect the favorable impacts of our increased production which was partially offset by a 6% decrease in the average sales price per Mcfe. When the impacts of cash settlements from our oil and natural gas derivatives are considered, oil and natural gas revenues were $240 million for the third quarter 2011 compared with $230 million for the second quarter 2011 and $174 million for the third quarter 2010.
- Oil and natural gas operating costs for the third quarter 2011 were $0.42 per Mcfe compared to $0.75 per Mcfe for the third quarter 2010. This 44% reduction in per unit operating costs reflects the significant impact of increased volumes from our horizontal Haynesville/Bossier shale wells, which produce high volumes of natural gas and have low per well operating expenses.
- 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 third quarter 2011 was $163 million compared with $116 million in the third quarter 2010.
- Cash flow from operations before changes in working capital, a non-GAAP measure, was $151 million for the three months ended September 30, 2011 compared with $108 million for the three months ended September 30, 2010, an increase of 40%.
Douglas H. Miller, EXCO’s Chief Executive Officer commented “Our results for the third quarter 2011 reflect our focus on well performance, capital and operating costs. Production grew 69% from the prior year despite curtailments, and we remain on track to exit 2011 at nearly 600 Mmcfe per day of net production. Our direct operating costs during the quarter decreased by 44% from the prior year to $0.42 per Mcfe, reflecting the high quality of our asset base. In DeSoto Parish, we continue to refine our production techniques and have successfully reduced our drilling and completion costs during the year. In our Shelby area, we are focused on further delineation in both the Haynesville and Bossier shales where recent IP’s were in excess of 27 Mmcf per day. Our drilling days have shown a marked improvement during the year resulting in reduced drilling costs. Results in our Marcellus acreage during the quarter have also seen improvements. During the third quarter, we turned 11 Marcellus wells to sales with an average IP rate of 5.8 Mmcf per day. As we begin our development program in the Marcellus, we are realizing reductions in our average well cost and expect further reductions as a result of drilling and completion efficiencies and building our water infrastructure. We are currently in the process of finalizing our 2012 capital budget. Although the low cost, high volume nature of our operations results in a satisfactory rate of return in the current natural gas environment, we are evaluating the appropriate level of our 2012 development activities.”
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