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British Columbia Usurps Alberta as Canada’s NatGas Production Growth Engine

British Columbia has taken over from Alberta as the source of growth in Canadian natural gas supplies for the next quarter-century, according to the National Energy Board (NEB).

The base, or most likely, case in a new NEB review of the country’s 10 provinces and three northern territories predicts that BC’s share of national gas output will nearly double to 46% as of 2040 from the current 27%.

The base case anticipates narrowly limited success by the score of proposals for liquefied natural gas (LNG) terminal projects on the northern Pacific Coast. Tanker cargoes for Asia are expected to take until 2023 to reach a plateau of 2.5 Bcf/d.

At most, in an unlikely but conceivable scenario of high gas prices and overseas sales successes, total Canadian LNG exports across the Atlantic and Pacific are seen hitting 4 Bcf/d in the mid-2020s and rising to 6 Bcf/d as of 2030.

The maximum tanker exports rated as possible are only 11% of a total 54 Bcf/d in NEB export license packages of 28 LNG terminal plans in varying stages of regulatory and commercial approval on both coasts -- but no construction anywhere yet.

The board does not identify the projects rated as most likely to succeed, and it calls the forecast LNG export volumes “only assumptions” rooted in a wide range of forecasts for global gas market conditions and Canadian fitness to win international competition.

But BC stands out in the NEB review as the new growth department of the Canadian gas supply sector even if the success rate for LNG export schemes turns out to be zero.

The leadership switch has long been anticipated by industry and government agencies since Alberta production peaked at nearly 14 Bcf/d in 2000, then entered a long, slow slide to the current level of about 10 Bcf/d.

Feverish drilling fueled by price spikes became an ever more expensive treadmill of completing as many as 20,000 Alberta wells per year into shrinking shallow targets left over from depleting large deposits discovered in previous decades.

The 2008 emergence of horizontal drilling and hydraulic fracturing in shale and tight deposits, driving supplies up and prices down, stopped the Alberta shallow gas grind. Relatively untouched, jumbo geological formations in northern BC turned out to be the most attractive arenas for Canadian adaptations of horizontal drilling and hydraulic fracturing.

NEB projections say BC will be Canada’s new supply development leader even if no LNG export terminals are built.

The board’s base case outlook shows BC production doubling to 8.2 Bcf/d as of 2040 from the current 4 Bcf/d if would-be LNG exporters land overseas contracts for 2.5 Bcf/d. If the coastal terminal projects all fail and gas prices remain permanently depressed, BC output is still forecast to grow into a range of 6 to 7.3 Bcf/d.

In the NEB base case Alberta gas output hovers at 9.5 Bcf/d, partly sustained by gas as a byproduct of drilling that has switched to fracking wells into liquids-rich shale and tight geological formations. The board foresees Alberta slipping deeper, into a range of 8 to 9.2 Bcf/d, if prices stay lean and the LNG export campaign fails.

Thermal oilsands projects continue to be market mainstays as the largest and fastest growing Canadian customer for natural gas.

In the NEB base case, where oil recovers to US$82/bbl in 2020 and US$107/bbl in 2040, production by the northern Alberta plants climbs by 78% to 5.4 million b/d. If the oil market does better and the industry overcomes environmental and aboriginal resistance against new pipelines, output reaches 6.2 million b/d. The plants use an average of 1 Mcf of gas per barrel of oil production.

The Canadian natural gas sector’s reliance on the oilsands showed when about 1 million b/d, or 40%, of production was shut down on May 3 because a forest fire forced the evacuation of all 88,000 residents of the bitumen belt capital, Fort McMurray.

While compelling the oilsands plants to let their employees leave to take care of their families, the wind-driven inferno nicknamed The Beast also forced a complete shutdown of the regional gas and power distribution grids.

The results included a sudden loss of an estimated 700-800 MMcf/d of northern demand and an outburst of bearish Canadian trading across the Alberta and BC supply collection grid, Nova Gas Transmission Ltd. The fire worsened a lean spell brought on by a mild winter and early spring across the western provinces.

Closing prices dropped to C$0.86/Mcf (US$0.67/Mcf) on Friday, May 6, then bottomed out on Monday, May 9, at C$0.77/Mcf (US$0.60/Mcf).

After the blaze swept past Fort McMurray and east towards northern Saskatchewan, and firefighters confirmed 90% of the city and all the oilsands plants were saved, gas recovered to the pre-disaster trading range of C$1.20-1.40/Mcf (US$0.94-1.10/Mcf).

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