Related Articles
In depth
Forward article link
Share PDF with colleagues

Shrinking Canadian expectations

The future of unconventional gas drilling in the western basins is uncertain because of the cancellation of several high-profile LNG projects

In Canada—and especially British Columbia (BC)—gas drilling is (or was) dependent on approvals for multi-billion-dollar liquefaction terminals on the country's west coast. Proponents had to demonstrate at least 20 years of proven reserves to secure export licenses. This, in turn, sparked a prolonged boom in unconventional shale plays such as the Montney. So, despite persistently low North American gas prices, Canadian drilling and production held up reasonably well—as long as there were proposed outlets for the fuel.

That changed in July 2017 after Petronas abruptly cancelled a proposed C$36bn ($28.9bn) terminal in Kitimat, on BC's northern shore. A sizeable portion of that outlay, some C$6bn, was allocated to its Canadian upstream subsidiary, Progress Energy. It was to tap the reserves needed to secure export permits from Canada's energy regulator, the National Energy Board (NEB).

Now it's becoming clear that those plans have been dramatically scaled back or even scrapped altogether.

In the weeks following its announcement, Petronas quietly sought offers for nearly half a million acres of gas-prone lands in BC, including drilling permits, held by Progress. The sale would also include interests in a trio of gas processing plants and pipelines and some 5,000 barrels of oil equivalent a day of production. Offers were due in November and, so far, there has been no indication of any takers.

Likewise, Shell and Chevron followed suit and pulled the pin on their own ambitious west coast LNG plans, which were backed by a host of international majors including Mitsubishi, Kogas and PetroChina—all of which struck upstream joint ventures with Canadian producers. Likewise, both Shell and Chevron are major gas producers in Canada's unconventional shales. The future of those production joint ventures is equally uncertain.

But despite the ominous foreshadowing, drilling and production in the Montney and the emerging Duvernay shales in Alberta continue more or less unabated. According to Peters & Co, a Calgary-based energy investment bank, Montney production hit 6.3bn cubic feet a day in October 2017, a record.

The British Columbia Oil and Gas Commission still expects the province's Montney gas output to quadruple to 11.6bn cf/d by 2020 from 3.7bn cf/d in 2013. But those forecasts were based on approvals for five major LNG terminals. IHS energy consultants are expecting a more modest, but equally optimistic, 7bn cf/d.

According to NEB data, Canada produced 15bn cf/d of gas in 2017, with 40% coming from the Montney. The figure includes 40,000 barrels a day of condensates, offsetting the impact of low gas prices. Condensates are priced off global oil benchmarks and at present fetch about $75 a barrel, a level Peters expects will hold through 2018.

"A number of the liquids-rich producers are generating strong operating cash flow strictly from condensate volumes," the brokerage noted.

Despite the uncertainty in BC, the situation is a little less ominous on the Alberta side of the border, where Duvernay production topped 1bn cf/d in the waning months of 2017 and continues to climb. Due to the geographic barrier posed by the Rocky Mountains, the vast majority of BC's output was to be funnelled offshore, while Alberta's flows the opposite direction to eastern Canada and the US Midwest. Alberta also enjoys well established transportation infrastructure and there's ample pipeline capacity to accommodate continued growth.

A high liquids cut ensures that the play will be economically viable at gas prices below $3 per million British thermal units, analysts say, making it cost-competitive with the big US shale plays in the Lower 48 states. Additionally, Alberta enjoys a robust domestic market for natural gas liquids, which are used to dilute bitumen and heavy oil from the oil sands to allow it to flow in pipelines.

An NEB report released in September suggested the Duvernay could eclipse the Montney as Canada's largest unconventional shale field—covering more than 20% of Alberta—with 6.3bn barrels of NGLs and 77 trillion cf of gas, not to mention 3.4bn barrels of light oil.

But uncertainty surrounds approvals for new oil-sands export pipelines, specifically Kinder Morgan's TransMountain expansion to Vancouver and TransCanada's Keystone XL to the US Gulf Coast, which may limit future growth and put a cap on demand.

That said, early Duvernay drilling results have been positive and the play is transforming at a slow and steady pace from a promising science experiment to a full-fledged producer in its own right. It may yet prove to be a bright spot in what is shaping up to be another challenging year for Canadian gas.

This article is part of an in-depth series on Global shale. Next article is: Mexico stuck in neutral

Also in this section
EV market accelerates on cost parity
19 September 2018
Not everyone is a friend of electric vehicles, but the sector is on a roll that will be hard to stop
Can Greece jump on the gas-transit train?
4 September 2018
Greece hopes to exploit natural gas pipelines crossing its territory to export its own volumes to Europe
Trudeau picks up the pipeline dossier
31 August 2018
The Canadian government is banking on its clout being sufficient to remove obstacles to a long-delayed oil export project