If pipeline and storage infrastructure can keep pace, natural gas produced from U.S. shale basins is expected to account for 18% of Lower 48 supply by 2015 — compared with the 8% of supply that shale gas accounted for in 2007, according to EnCana Corp. The Calgary-based producer, whose leaseholds are spread across unconventional gas basins in the United States and Canada, is shooting to be the leader of the pack, executives said Thursday.

Jeff Wojahn, president of EnCana’s USA division, credited early success by other producers in the Barnett Shale, combined with the continued evolution of new field technology, for the phenomenal growth of shale gas prospects. The emerging shale plays all begin and end with what happened in North Texas less than 10 years ago, he said.

“There’s no denying it, gas shales are the fastest growing market segment in the United States,” said Wojahn. “In my mind, it all starts off with the Barnett Shale, the most amazing gas shale play I’ve seen in my career…You can talk about coalbed methane, talk about the San Juan [basin], but Barnett is the bell cow,” he said, referring to a team’s lead runner. “The world’s full of shales, but the Barnett…still has a lot of room to grow.”

Wojahn shared the podium with EnCana’s management team in Calgary to provide an overview for investors of what’s ahead as EnCana prepares to split the company into two entities: one a pure-play unconventional gas producer and the other an integrated oilsands business (see Daily GPI, May 13). With the exception of its Deep Panuke gas project offshore Nova Scotia, all of the gas company’s assets would “essentially be onshore,” CEO Randy Eresman noted.

EnCana is one of the top producers in the Barnett Shale, but it also holds substantial acreage in proven and emerging unconventional gas plays across the United States and Canada. All together EnCana has around 1.25 million net acres of leasehold in North America and at least a 10-year inventory of prospects, Wojahn said. Most of the recent buzz has centered on the emerging Haynesville Shale in northern Louisiana and the Horn River Basin in British Columbia — two areas that EnCana is beginning to develop. But Wojahn was quick to note that EnCana’s future production may — or may not — come from the hot, new plays.

“A lot of people ask, may wonder, why doesn’t EnCana put all of its work in the Haynesville, or all of it in Horn River,” Wojahn said. “Clearly, the potential of these plays is outstanding.” However, the North American shales “all look the same to me from a geological point of view. They are all thick; all of them have a lot of gas in place…all of these plays have it. The proof is in the pudding.” Whether the hype pans out about estimated reserves from the newest basins remains to be seen, and the results will take a lot of work and a lot of time. “We need to maximize the new technology and have an understanding ultimately of what the cost structures are, where the supply costs shake out. I’m not smart enough to know which one is the best, how much gas is in each of them.

“But we want to drill a significant amount of statistical wells, not one well, not two wells, to have a good understanding” of the costs and the estimated reserves, Wojahn said. “It is my belief that a couple of these plays will end up in our key resource portfolio,” he said of Horn River and Haynesville. EnCana now concentrates its U.S. efforts in four areas: Jonah, Piceance, East Texas and the Barnett. A lot of “noise” has been heard about the Haynesville from Chesapeake Energy Corp. and others, he said, and rightly so. Already EnCana has a “couple of wells over 5 MMcf/d” testing in Haynesville. Another well in Horn River has tested at around 10 MMcf/d.

“We’re very encouraged on the future of those plays. Stay tuned. We’ll have more to say about how it fits into our portfolio this fall…Clearly we are doing things that are remarkable in the gas shale world.”

Bill Oliver, midstream and marketing division chief, said EnCana’s long-term forecast for gas prices is around $8.50/Mcf.

“One of the criteria for investment is the cost of entering new basins,” Oliver said. “Based on the studies we’ve done and those by others, the marginal cost to enter the basins still appears to be $8 to $8.50.” EnCana has undertaken a “pretty major study” on the supply basins in North America. “We were surprised, we didn’t expect the rate of development we’ve seen from the Rockies, and we had to step back and look at the new supply picture. We’re comfortable long term, and we’re still looking at new basins, especially where gas prices are.”

“New information on wells is being completed every day,” noted Eresman. “There’s been a step change in North American gas that came faster than we anticipated, and prices are higher than we expected at this point, but we’re ready. We’re in a manufacturing mode, and again, we’re seeing advancements in technology, advancements in technique, that are able to continually drop the cost. As an end result, it continues to lower the average supply costs. We’re pretty happy with future commodity prices if natural gas is in the $8 range, that’s enough to provide a significant return for EnCana.”

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