Canada has abundant gas resources that could support a sizeable LNG export industry. But numerous barriers—geographical, financial and regulatory, among others—stand between existing gas fields and future LNG loadouts at tidewater.

Jeff Fetterly, principal for oilfield services analysis with Calgary-based Peters & Co. Ltd., told attendees at Hart Energy’s recent North American LNG Exports Conference in Houston that multiple projects are progressing through permitting reviews with greater clarity on which plants will be built to come within the next six months.

“Asia is clearly the greatest market opportunity for most of Canadian LNG exports,” Fetterly said. “There is supply at a deficit to demand and, as a result, there is an opportunity here for North American LNG—and specifically Canadian LNG.” However, he pointed out that worldwide, there is more liquefaction capacity under construction now than regasification capacity “so the race is on” among potential LNG suppliers. “We think North America is competitive from a project standpoint,” he added.

But like the U.S., which has multiple proposals now, not all of Canada’s liquefaction operations will be built. At least 14 LNG projects have been proposed for British Columbia’s Pacific coast with multiple proposals clustered at the ports of Kitimat and Prince Rupert. Also, two U.S. projects proposed in Oregon—Jordan Cove and Oregon LNG—would be served primarily with Canadian gas. There are four proposals on Canada’s Atlantic coast in New Brunswick and Nova Scotia, Fetterly noted.

“Altogether, about 130 million tons per annum have been proposed at present, obviously nothing has reached the sanctioning phase. When you look at a full-phase buildout, including subsequent trains, you’re looking at some 300 million tons per annum” if all were built, he said.

“One thing that clearly stands out is the capital cost for all of the projects,” the analyst said. A three-train project, similar to the one Petronas has proposed at Prince Rupert would represent a $100 billion investment over a 25-year period. Peters estimates an unleveraged IRR of 10% to 11% for a Canadian West Coast facility.

“It’s competitive, but at a modest deficit to what we’re seeing both on the West Coast and the Gulf Coast of the U.S.,” Fetterly said. “Below a lot of people’s radar screen” are several floating LNG projects for Canada’s West Coast. Such FLNG operations have the potential “to be quite competitive,” he noted, “and would have a lot more flexibility” than land-based liquefaction plants.

The typical model of a Canadian LNG project is vertically integrated “so you would have significant upstream costs.” Upstream drilling and production could make up as much as two-thirds of a project’s expenditures. He noted the Petronas project and Shell’s proposal for Kitimat are both backed by sizeable reserves in the Montney play of northern Alberta and British Columbia, although wells in the region cost $8 million with infrastructure.

“We estimate that the Petronas project would have to drill 6,000 wells over the span of 25 years to meet the needs of that project,” he said.

Strong points Canada has to support LNG exports are an active drilling program, existing production of some 15 billion cubic feet per day (Bcf/d)—with declining U.S. export demand—and a comparatively good transmission grid. However, laying new pipe over the Rockies to the coast would be required and that will be expensive. Competing pipeline projects to the coast are a cost liability but there is the potential of competing partners to combine proposals.

“The capital cost to build a pipeline, from the Montney, both on the British Columbia side and the Albert side, to the coast is significant, for topography, capital and time,” he said, adding a pipeline alone could cost $7 billion or more or $1 or more just for pipeline tolls and “obviously consolidation will be required.”

The Montney and Horn River plays have significant gas resource potential and one or more large LNG operations would have “a significant impact” on the pace of development, he said. Current gas production in the region is around 3.5 Bcf/d while a large scale LNG export industry would require an additional 3 Bcf/d of supply.

He rated the Petronas and Shell projects as the most advanced with each having multiple, strong partners involved.

Fetterly noted comments at the conference about “onerous” U.S. regulatory reviews but noted “Canada has the potential to lap it.” He explained that Canadian LNG projects have significant review obligations at the federal level, the provincial level and by impacted aboriginal nations. He noted one pipeline proposal is subject to review by 31 different First Nations. Also, British Columbia tax obligations could be large.

Added to those challenges, considerations for labor and comparatively little supporting infrastructure in remote regions of northern British Columbia are key factors. Labor, in particular, is a concern given the high demand for labor in Canada’s nearby oil sands and the region’s light population.

“The resource is significant and the proximity to market is very attractive,” positives that balance significant capital, regulatory and infrastructure risks, he said. “We think Canadian LNG will be built. Our view is that between one and three projects will be commissioned by 2015—that’s a nice, wide goal post to go through.”