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EOG makes ‘really, really’ big shale gas discovery in NE B.C
There’s not much doubt that EOG Resources is under a full head of steam in the United States as it rolls out plans to expand the Barnett Shale natural gas province into an oil play, uses its horizontal drilling techniques to revolutionize global onshore exploration, taps into an oil play in North Dakota’s Bakken trend and reveals two new oil plays in the North Park basin of northwest Colorado.
But its hottest prospect may lie in the remote Horn River basin of northeastern British Columbia where its experimental new resource play may contain as much as 6 trillion cubic feet of shale gas reserves from a net 140,000 acres, matching the three anchor fields on the Mackenzie Gas Project.
Loren Leiker, EOG vice president of exploration, told the independent’s annual analyst meeting the Muskwa shale may be what many have been searching for — a match for the prolific Barnett deposit.
“We think we have found shale in British Columbia that is every bit the quality of Barnett,” he said.
Leiker said EOG believes that 50 percent recovery from the water-free Muskwa wells is “not off limits,” although it is assuming recovery efficiencies of 20-30 percent.
“It takes only 20 percent recovery on 60 percent of our acreage to get the 6 tcf number,” he said.
Although emphasizing that more time is needed for a thorough review, Leiker described Muskwa as a play with “world class rock properties” that are thicker and higher pressure than Barnett and have double the gas in place in the Barnett’s core Johnson County area.
On top of that, he said the infrastructure is in place for initial gas sales in June and volumes of 40 million cubic feet per day by 2010 or 2011.
EOG: magnitude underestimated “This, in my opinion, is a really, really big deal,” EOG Chairman Mark Papa told the analysts.
“The magnitude of this is currently underestimated by Wall Street as well as perhaps a lot of other E&P companies.”
That might have changed. EOG shares bounced up 18 percent the next day, while EnCana and Nexen — two leading players in the Horn River shales — gained 3 percent and 5 percent, respectively.
Chris Feltin, Tristone Capital’s research director, endorsed the notion that the Horn River basin could match Barnett’s shale potential, although it will take time to develop.
FirstEnergy Capital analyst Stephen Paget put the EOG find among the top 10 gas discoveries in Western Canada, but he notes that Horn River’s gas, unlike large single pools, is trapped in rocks over a large area, making it more difficult to produce.
Papa said that until six months ago EOG had not drilled the wells to determine whether what looked like and quacked like a duck was really a duck.
The answer has come from test rates of 3.5 million and 4.2 million cubic feet per day over 10- to 14-day periods from 1,700-foot horizontal wells, compared with the 3,400-foot laterals EOG will use for commercial production, when output will likely double, he said.
Papa said that 3,300-3,400 foot laterals in Barnett would yield up to 8 million cubic feet per day.
Horn River winter-only access He did concede that Horn River will be slower to develop than Barnett because it is a winter-only access area and because of its remoteness well costs will be higher than Barnett, while there will be a “significant location differential” relative to Henry Hub prices.
EOG’s current estimate points to a “very large asset that will ultimately generate a 20 percent pretax rate of return,” Papa said.
More development wells this year will help EOG refine its drilling and completion processes. In Papa’s view, however, Horn River has cleared the technical hurdles, leaving the company to deal with execution and logistics.
On the infrastructure front, EOG has just acquired a 24 million cubic feet per day conditioning plant, is installing a 10-mile gathering line to tie in its first drilling area, while a pipeline with capacity of 65 million cubic feet per day, which EOG hopes will be looped in 2010 or 2011, will carry gas south to the Fort Nelson gas plant.
Leiker estimates the Fort Nelson plant has incremental capacity of 450 million cubic feet per day, capacity that will have to be supplemented “if this play is as big as we think it is.”
Horn River is exactly what many leading Alberta producers need as an alternative to Alberta’s new royalties.
Along with EOG, EnCana and Nexen, Apache Canada and Devon Canada are shifting more of their resources to British Columbia.
—Gary Park
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