Canada’s East Coast currently offers Husky Energy Inc. a more likely prospect for a major development than the Canol oil shale in the Northwest Territories, a senior executive said today.

“Right now you have to say the opportunities for Atlantic Canada development in that 2020 timeframe today look more attractive than a Canol,” said Rob Symonds, Husky’s senior vice-president for Western Canada production.

Symonds made the comment at the annual BMO Capital Markets unconventional resource conference in New York.

Husky currently produces about 50,000 bbls of oil a day from the relatively shallow waters of the Jeanne d’Arc Basin east-southeast of St. John's. That production comes from the Husky-operated White Rose project and the Terra Nova field operated by Suncor Energy Inc.

By developing White Rose satellite fields, Husky hopes to maintain its offshore Newfoundland output at around 50,000 bbls a day and extend the life of its floating, production, storage and offloading (FPSO) vessel.

“We certainly do have some exploration opportunities around White Rose that could give us a bit more,” Symonds said. But the real success in Atlantic Canada has been the deep water -- the Flemish Pass.”

Husky and partner Statoil ASA have already made three major oil discoveries in roughly 1,300 metres of water in the Flemish Pass Basin, about 500 kilometres northeast of St. John's.

The first was the 2009 Mizzen find where Husky’s best estimate of recoverable contingent resource is 120 million bbls (gross).

Last year, Husky and Statoil announced discoveries at Bay du Nord (400 million bbls of best-estimate recoverable contingent resource) and Harpoon.

Husky and Statoil are trying to secure a rig to drill a delineation well at Harpoon before issuing a recoverable resource estimate oil for that discovery.

“We think those three assets that we have are themselves sufficient probably for a deepwater development,” Symonds said. “Timing on that is ... probably towards the end of the decade -- 2019, 2020, 2021.”

Statoil is the operator of Mizzen, Harpoon and Bay du Nord with a 65 per cent interest. Husky Energy has a 35 per cent stake.

While this would be Canada’s first deepwater project, Symonds emphasized the technology for deepwater development has long been proven elsewhere in the world.

White Rose gas

However, it is less clear what technology would be used to deliver to market the massive natural gas resource at White Rose.

While Husky is bullish about Newfoundland oil, there is still no certainty on when the province’s first gas development will occur.

The Canada-Newfoundland and Labrador Offshore Petroleum Board estimates the White Rose recoverable gas resource at 3.02 tcf. But even when gas prices were strong, the challenge was to find an economic way to get the gas to market.

According to C-NLOPB’s November 2013 estimate, the entire discovered offshore gas resources around the island and off the Labrador coast total 12.19 tcf. But unlike offshore Nova Scotia gas -- which is piped a relatively short distance through iceberg-free waters -- Newfoundland gas remains stranded because of the cost of building a pipeline deep beneath an iceberg-scoured seabed.

Asked on Tuesday about the prospects for developing White Rose gas, Symonds suggested it isn’t going to happen anytime soon.

“Right now I’d say it’s post 2020. We’re looking at it,” he said. But given current North American gas prices, “you clearly don’t see much value in that.”

Oil shale

In Western Canada, Husky is evaluating two potential tight oil opportunities. These are the Muskwa shale formation at Rainbow Lake in northwest Alberta and the Canol shale formation in the Central Mackenzie Valley of the Northwest Territories.

Husky has had conventional operations at Rainbow Lake for about three decades. Pipelines and other infrastructure are in place to get the crude to market.

“The challenge right now is that the rock -- this is a Duvernay equivalent rock -- is not as over-pressured as it is further south. And as a result the deliverability we’re getting per frac stage at the moment doesn’t justify the money,” Symonds said.

So the big challenge in the Muskwa shale is to find an economic way to develop it -- for example, more but smaller fracture stimulation stages.

In the Canol shale, meanwhile, the prize is huge, but so is the challenge.

To put the Canol size in perspective, Symonds said the Bakken can have five million bbls of oil-in-place per section, the Muskwa at Rainbow can have roughly 20 million bbls per section while the oil-in-place in the thick Canol shale can be as much as 80 or 90 million bbls per section.

While the Canol appears to have better permeability, it is not over-pressured and there is no infrastructure in place, he said.

“We have only a three-month working window in the winter. We have built an all-weather road so we can get a three-month working window in the summer,” Symonds said. “But the real challenge for us is: what is the type curve? Can we afford to build the infrastructure up there to go to year-round activity?”

He said Husky and some other Canol operators are sharing information so they can avoid duplicating each other’s mistakes.

“But right now, we’re not looking to drill. We drilled two vertical wells, we’ve proved there’s hydrocarbons in the system. We’re looking to drill horizontal wells in the winter of 2015-16,” he said about the Canol. “And that’ll allow us to make a long-term determination of deliverability -- because we’re going to need a long-term test. And it’s the logistics of a long-term test that are holding us back.”

Given the competing opportunities within the company, the senior vice-president said the chances of Husky doing a development offshore Newfoundland around the end of the decade currently look more attractive than a Canol development.