Editorial: Canada’s Gas Industry at a Crossroads
This article is featured in NGW Magazine Volume 2, Issue 19
Although much of the discussion about Canada’s place in the global energy universe surrounds crude oil, from future oil sands development to export pipelines, the country’s natural gas industry is equally at a crossroads.
Like many of the concerns worrying crude oil producers, the natural gas angst is related to the explosive growth of energy production from south of the border. The US, once Canada’s only market for surplus natural gas, is now one of its key competitors on the global gas market, and is, to use the vernacular, eating Canada’s lunch.
Over the last decade, the US has taken the shale gas ball and run with it, boosting domestic dry natural gas production by 40%, to an estimated 73.69bn ft³/day this year from 52.8bn ft³/day in 2007, according to US Energy Information Administration (EIA) data.
The increased domestic production has allowed the US to gradually reduce pipeline imports – mostly from Canada – to 7.9bn ft³/day this year from more than 10.5bn ft³/day in 2007. And the shale gas bonanza has spurred dramatic growth in US LNG export capabilities: from just 1.3mn ft³/day of LNG exports in 2007, the EIA is forecasting US LNG exports to average more than 3bn ft³/day in 2018 and to exceed 12bn ft³/day by 2035.
Those statistics are at the crux of Canada’s current natural gas dilemma. With their key export customer no longer reliant on Canadian gas, and domestic demand growth stagnant, Canadian gas producers must access global LNG markets – notably those in Asia – if they hope to have any chance of monetising their productive potential.
But unlike the US, Canada has been slow to join the LNG dance: although 20 or more projects have been proposed for the west coast of the Canadian province of British Columbia – a short 10-day sail to Asian ports – only one, the relatively modest 2.1mn metric tons/year (mt/yr) Woodfibre LNG project, has made a final investment decision (FID) to proceed. And in the last couple of months, two major projects, the 12mn mt/year (expandable to 18 mn mt/year) Pacific Northwest LNG project and the 24mn mt/year Aurora LNG project, have been scrapped.
Whether any of the remaining 18 west coast LNG projects will eventually proceed – there are hopes that two, or perhaps three, will be sanctioned in time to meet the next LNG demand window post-2025 – remains at best uncertain.
Environmentalists are opposed to most LNG projects because of the increased greenhouse gas emissions they represent; indigenous First Nations can block projects if they impinge on traditional lands or if they don’t receive sufficient financial benefit from them; even the federal government, led by the prime minister, Justin Trudeau, has been lukewarm in its support for LNG export projects.
With pipeline export markets in the US drying up and LNG export hopes left standing in the starting gate, Canadian producers are at loose ends as to what to do with their gas, which is backing up behind the pipe in Alberta. In the third week of September, for example, field receipts into pipelines gathering gas in the three western Canadian provinces of British Columbia, Alberta and Saskatchewan averaged some 15.5bn ft³/day, according to estimates by investment bank GMP FirstEnergy. But demand in those provinces averaged only 5.3bn ft³/day, leaving more than 10bn ft³/day sloshing around without a home and sending local prices plummeting.
In the days before the shale gas gale blew through the US, any surplus of western Canadian natural gas would have easily been soaked up by gas-hungry markets in the heavily populated eastern Canadian provinces of Ontario and Quebec, or moved across the border to equally-hungry markets in the US Northeast or Midwest.
Now, however, with production from the northeast US Marcellus field approaching 20bn ft³/day and Utica production exceeding 4.5bn ft³/day, the proximity of those two sources to eastern Canadian gas markets is making it difficult for Canadian producers to compete for sales.
Exacerbating those difficulties is inadequate capacity to even move gas from the key Montney shale fields in northeastern BC and northwestern Alberta to western Canada’s AECO trading hub, where it can flow into pipelines serving eastern Canada and the US. In less than a year, the spot price at AECO has plunged from C$3.73/GJ to, on certain days this past summer and fall, negative C$0.55/GJ. In other words, Canadian producers are paying to have someone – anyone – take their gas.
If those kinds of economics prevail, there is little doubt that significant volumes of Canadian natural gas – some suggest as much as 3bn ft³/day, most of it from shallow stripper wells that produce less than 20,000 ft³/day in eastern Alberta and western Saskatchewan – will have to be shut in.
But that prospect is itself troubling for many producers, since shutting in so many marginal wells would render them essentially uneconomic, and subject their owners to abandonment liabilities that could reach C$10bn or more.
Such, then, is the plight of the western Canadian natural gas producer. Production potential abounds across the Western Canadian Sedimentary Basin, which spans BC, Alberta and much of Saskatchewan. But without access to global, or even domestic, markets, much of that potential might yet go unfulfilled.