EOG Resources (EOG) held a conference call on November 2, 2010, to discuss earnings for the third quarter of 2010, and discussed the company’s activities in the Eagle Ford Shale in Texas.
“The reservoir can be broken into two zones, East and West. In the East, we have two targets, the Upper and Lower Eagle Ford. These zones are relatively thick and high-quality. A typical well here is the Harper #10H well, which IP-ed at 1,070 barrels of oil per day and 980 Mcf per day. In this same area, the Cusack Clampit wells, which were highlighted in the press release, IP-ed at rates ranging from 860 to 1,800 barrels of oil per day, with 1 to 1.8 million cubic feet a day of rich gas each. We have 100% working interest in all these Eastern wells. In this Eastern area, we typically drilling 4,000-foot laterals and expect the average reserves per well of 460 Mboe net after royalty.”
“The typical decline curve for both areas indicate we'll produce 40% of our wells' reserves in the first five years. We originally thought we'd need roughly 2,800 wells to capture the 0.9 billion barrels of oil equivalent. But now it will take us a lot fewer wells to monetize this asset. Overall, we believe we can achieve a $12 to $15 per Boe direct finding costs across the entire play. We plan to run 14 rigs, drill 231 net Eagle Ford wells in 2011.”
“The direct rates of returns that we expect to achieve from both East and Western wings of our sweet spot will return to the same return goals as we gave at our April analysts conference. As we exit the science stage and enter the program drilling phase in 2011 and 2012, we expect to achieve the 0.66 and 95% direct after-tax rates return. In order to decrease our average completed well costs back to the original range by the end of next year on a normalized lateral length places, we're implementing drilling enhancements and completion design modifications as well as contractual and self-sourced frac solutions.”
‘Well costs in the Eagle Ford Shale are currently higher than what we forecasted in our April analyst conference. And we're working to get those down. I mean the primary reason is the fracturing costs there are in rough terms, maybe as much as $1 million higher than what we had estimated previously. And we hope by mid-2011 with some of this outsourcing that we're talking about, we can get those costs more in line. But the costs have gone up, but also the reserves have gone up because we're drilling longer laterals. So in terms of the returns, this is likely to be an awesome project on the terms, unless oil prices collapse.”
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