Canada’s dormant Arctic project is more than replaced by the latest and largest plan for liquefied natural gas (LNG) exports from the northern Pacific Coast of British Columbia (BC) at Kitimat.

The tanker port and BC pipeline scheme calls for Asia-bound shipments of 3.3 Bcf/d, or about double the ultimate capacity that had been envisioned for the frozen Mackenzie Gas Project.

LNG Canada Development Inc. has applied to the National Energy Board (NEB) for a license to export 32.95 Tcf over 25 years, a volume equal to 48% of the current combined reserves of Canada’s main gas-producing provinces, Alberta and BC.

The long-range LNG export target is also 5.5-fold bigger than the 6 Tcf of Mackenzie Delta reserves that were dedicated to the suspended Arctic production and pipeline development. Canada’s share in the shale gas revolution — in the words of technical reports filed with the NEB to support the application — drives the mammoth plan.

Most of the supplies are forecast to come from accelerating use of horizontal drilling and hydraulic fracturing technology transplanted from the United States to the Horn River Basin shale formation. The basin is roughly east of the Alaska Highway between Fort Nelson and the border between the northern top of BC and the Yukon.

Even if all the gas needed to fulfill the volume target comes out of the Horn River, the LNG Canada export license will only use up one-third of production expected from BC’s shale gas mother lode.

Canadian industry and government consensus forecasts estimate that the Horn River shale, a layer 2,500-3,000 meters (8,175-9,810 feet) deep beneath 12,800 square kilometers (4,900 square miles) of northern forest and muskeg swamp, contains 500 Tcf of gas.

Optimistic supply projections in the NEB filings are corroborated in a new 230-page primer, “The Modern Practices of Hydraulic Fracturing: A Focus on Canadian Resources,” which was prepared by Tulsa-based ALL Consulting LLC for two industry agencies: Petroleum Technology Alliance Canada and Science and Science and Community Environmental Knowledge Fund.

Current methods are rated as capable of producing 20% of the Horn River deposit, or 100 Tcf. But the numbers are likely to increase as the industry gains experience with the technology under BC conditions. Initial production from Horn River wells is up to 16 MMcf/d. The formation is so saturated in gas that their first-year output decline rate is only 50% compared to 90% in other shale basins.

LNG Canada is a subsidiary of Shell Canada, which has put its share in the Mackenzie project up for sale but attracted no takers. The company is doing much better at landing support for the mammoth BC tanker export scheme by luring investment from potential overseas buyers and merchants of Canadian gas.

A formal joint ownership agreement is being negotiated with Diamond LNG Canada Ltd. (a subsidiary of Mitsubishi Corp.), Kogas Canada LNG Ltd. (an affiliate of Korea Gas Corp.) and Phoenix Energy Holdings Ltd. (an affiliate of PetroChina Investment Hong Kong Ltd.), the NEB export license application said.

The plan calls for Shell to own 40% of LNG Canada and operate the project while the Japanese, Koreans and Chinese each take 20% ownership and market corresponding shares in the tanker shipments.

The development agenda says the terminal will be built in stages as four equal-sized production trains, with construction timing to be driven by market conditions. With the plant still in early design stages, no formal cost projections have been presented to the NEB.

But the sponsors estimate the total package could eventually run into the range of C$20-24 billion (U.S. dollar at par), including a C$4-billion pipeline to be called Coastal GasLink and built by TransCanada Corp. The Mackenzie project was forecast to deliver at most one-half of the gas for an initial outlay of C$16 billion or 66-80% of the cost of LNG Canada.

The marketing schedule is likewise unsettled, with the international consortium keeping its options open. Canada LNG is asking the NEB to grant an export license that will stay valid for 10 years without deliveries beginning and only expire if shipments fail to start as of Dec. 31, 2022.

Time needed to jump through Canadian regulatory hurdles was shortened as of June by enactment of a pro-development federal reform package that set brisk schedules for project reviews and abolished environmental assessments for gas-export license applications (see Daily GPI, May 14).

While acknowledging that it has rivals in Australia, the Middle East and the United States, Canada LNG maintains that it is starting out with an edge on a growing international gas market.

The advantages only start with a terminal location where the tanker voyage time from BC to Japan of eight to 10 days is competitive with Australian LNG sources and beats the two-week travel times for Middle Eastern suppliers, said a markets study done for Canada LNG by consulting firm PFC Energy.

“LNG Canada’s project structure is a big asset,” PFC told the NEB. “The project’s prospects are bolstered by its ownership structure. Shell, Kogas, Mitsubishi and PetroChina bring extensive experience in all aspects of the LNG value chain including upstream [production], liquefaction, shipping, re-gasification and access for LNG output to financial, technical and commercial resources.”

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