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Energy and Resources Drop in oil prices means no drilling in Canada’s biggest shale reserves

View looking east on an Air North flight between Whitehorse, Yukon and Inuvik, Northwest Territories, on July 23 2014.

Fred Lum/The Globe and Mail

The news was bittersweet for Canada's Northwest Territories.

While the region found out last week that its Canol and Bluefish formations hold Canada's largest shale oil reserves, the slump in prices means no one's drilling there any more.

Exploration in Canol shale costs three to four times more than in northeast British Columbia, as the remote region lacks roads and infrastructure, said John Hogg, former vice president of exploration and operations for MGM and current president of Skybattle Resources Ltd., a consulting company. A 500 to 800 barrel-a-day horizontal well may be profitable with oil at $75, he said in a phone interview Monday. Benchmark West Texas Intermediate oil traded near $58 a barrel Tuesday.

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"What this really sets us up for is the long game," Dave Ramsay, the territory's industry minister, said in a phone interview from Yellowknife, late Friday. "People are noticing the assessment and the numbers are staggering."

The formations, in the centre of the arctic territory, hold about 190 billion barrels of oil in place, more than any other shale play that has so far been assessed by the National Energy Board, the agency said Friday.

ConocoPhillips and Husky Energy Inc., two companies that were exploring the Canol, say they have suspended further work in the area after oil prices plummeted. In December, Chevron Corp. put on hold drilling in the Beaufort Sea, another blow for the territory.

The National Energy Board's report pushes the Canol and Bluefish formations ahead of Alberta and British Columbia's Montney shale, which holds 141 billion barrels, as well as the 71 billion barrels on the Canadian side of Bakken, Stacey Squires, an NEB spokeswoman, said in an e-mail Friday. Other Canadian shale formations, including the Duvernay, haven't yet been assessed, she said.

Earlier estimates were that Canol and Bluefish held no more than 7 billion barrels in place, Mr. Ramsay said.

The amount of oil that could be recovered and sold wasn't estimated as well-test results aren't yet publicly available, the NEB said. The formation is most similar to the Permian Basin of Texas, which has a recovery rate of 3 per cent, the agency said.

Energy producers have been cutting capital expenditure as oil prices tumbled after the Organization of Petroleum Exporting Countries failed to reduce production quotas amid a surge of U.S. shale-oil production. WTI crude fell as low as $42.03 in March from last year's high of $107.73 in June. It slipped $1.69 to settle at $58.03 a barrel on the New York Mercantile Exchange Tuesday.

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ConocoPhillips doesn't plan further exploration in the Canol shale play "for the foreseeable future" after drilling four wells in the 2013-14 season, Kristen Ashcroft a company spokeswoman, said in a May 24 e-mail.

While remaining part of the company's "long-term growth portfolio," Husky suspended its exploration plans in spring last year, Mel Duvall, a company spokesman, said in an e-mail Monday. The new assessment hasn't changed the companies' outlooks, Ms. Ashcroft and Mr. Duvall said.

In December, Chevron said it delayed indefinitely a project to drill in the Beaufort Sea because of "economic uncertainty."

Another company that was exploring the Canol, MGM Energy Corp., said last year it suspended drilling after failing to find a partner to assist in funding further work. MGM was later fully acquired by Paramount Resources Ltd.

Enbridge Inc.'s 50,000 barrel-a-day pipeline extending from Norman Wells in the territories into Zama, Alta., isn't sufficient for developing shale resources and a new pipeline would take 8 to 10 years to develop, said Mr. Hogg of Skybattle Resources.

While the drop in oil prices hasn't helped, the biggest impediment in the NWT are the environmental assessments that create uncertainty for investors and are more burdensome than in other regions, such as Alberta, Mr. Hogg said.

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"Most people will walk away because the risk of seeing a successful exploration project move to development is too high due to the regulatory current process," Mr. Hogg said in a May 25 e-mail. "They really need reform of their process so that they have a clear line of site from exploration to production."

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