British Columbia will eclipse Alberta as Canada’s top gas producing province by tapping prolific shale deposits, the National Energy Board said.

Canada will stay in the natural gas export trade after all, said the National Energy Board (NEB) in a new 25-year forecast that recognizes emerging unconventional supplies for the first time.

By 2019 British Columbia (BC) will eclipse traditional mainstay Alberta as Canada’s top gas producing province by tapping prolific shale deposits with horizontal wells and hydraulic fracturing, said the NEB’s reference case of most likely industry evolution.

Discarding previous forecasts of drastic shrinkage, the board predicts that Canada’s annual gas exports will still be 3 Tcf in 2035, down only 17% from 3.6 Tcf this year. The drop will result from rising industrial consumption by Alberta thermal oilsands projects rather than previously anticipated failure to replace depletion of the province’s aging conventional gas pools, NEB said.

“By 2016 increasing Canadian tight and shale gas development reverses the current downward trajectory in Canadian natural gas production. The trend continues, with production reaching the record levels of 2001 near the end of the projection period (2035),” the NEB forecast said.

In the reference case outlook, “Natural gas supply increases by 33% from 2011 to 2035,” to a national total of 18 Bcf/d, “but demand increases by 51% from 9.9 Bcf/d to 15 Bcf/d in 2035. Demand increases in Canada are largely from the oilsands sector and for power generation,” the board said.

The NEB makes no guess at how the continuing high volumes of Canadian gas available for export will be marketed. While much of the industry remains focused on pipeline deliveries into the United States, the board recently granted an export license to the first in a lineup of liquefied natural gas (LNG) terminals proposed to load up tankers bound for Asia from BC’s northern Pacific Coast (see Daily GPI, Oct. 17).

The NEB forecast’s reference case, developed in consultation with industry and financial analysts, predicts annual average North American gas prices will take until 2035 to recover to US$8.00/MMBtu. No attempt is made to project higher levels that the industry expects LNG to fetch in Asia, where gas is routinely linked to oil by pricing indexes in long-term contracts.

The natural source for LNG exports — the Horn River Basin in northeastern BC — is expected to be the Canadian hot spot for gas supply growth, with 78 Tcf of marketable reserves already recognized even though development remains in its early stages.

Gas from the Mackenzie Delta only begins to show up in Canada’s revised production outlook in 2020, about a decade later than the target set by the industry’s C$16.2 billion (U.S. dollar at par) Arctic megaproject when its construction application was filed with the NEB in 2004.

Approved last winter, the northern pipeline and production scheme remains in a limbo of fiscal negotiations with governments. The board calls its Arctic gas arrival date an assumption rather than a prediction.

As of 2020 the NEB reference case foresees BC production doubling to 7 Bcf/d. At the same time Alberta is expected to tumble to 6.1 Bcf/d, down by 34% from its current 9.2 Bcf/d.

The forecast anticipates that Alberta gas production will stagnate at or slightly below 6 Bcf/d for the next 25 years, with new shale supplies barely making up for depletion of conventional pools.

Nearly two-thirds of Alberta’s own gas output is expected to be required to fuel steadily expanding oilsands projects, led by in-situ or underground extraction with steam injections.

Oilsands industry gas consumption is expected to about triple to 3.7 Bcf/d as bitumen output also triples to 5.1 million b/d. The NEB observes that while bitumen developers are gradually paring their gas use, the fastest-growing part of the industry is also its least energy-efficient: steam heating the four-fifths of the northern Alberta deposits that are buried too deeply for open pit mining.

Gas production offshore Canada’s east coast, currently about 280 MMcf/d, is expected to hit a peak of 665 MMcf/d in 2021 if current plans for oil platforms on the Grand Banks of Newfoundland are carried out. The board said the Atlantic growth outlook will come true if offshore oil reserves are depleted as expected, creating an incentive for producers to market gas that is currently being reinjected to preserve pressure in geological reservoirs.

Producing up to 500 MMcf/d is rated as possible from oil platforms 300 kilometers (190 miles) out to sea on the Grand Banks. “Newfoundland gas is slated to reach market in 2020, but this could be delayed by the discovery of additional oil pools or unfavorable economics of bringing the gas to market,” the NEB said.