It’s time for the Alberta government to think outside the box.

The province’s oil and gas industry was hammered hard by the 2014-16 collapse in international crude prices, and its revival has been less than stellar with prices rebounding to moderate levels. It has been widely argued that the age of the oilsands mega-project has come to an end. The high-cost, high-carbon resource is out of vogue, especially among international oil companies (IOCs) that have deserted the industry en masse, generally for the greener, lower risk pasture of U.S. light tight oil (LTO).

As a result, the provincial government should refocus its energies and resources away from the oilsands industry, and re-establish an Alberta Advantage to rapidly develop as much of our own substantial tight oil resource as possible before the global carbon budget runs dry.

Many IOCs are increasingly focusing their upstream investment on short-cycle, mid-cost U.S. LTO resource, to boost profits and mitigate risk in a relatively low oil price environment — a trend recently accentuated by President Donald Trump’s corporate tax cuts. Earlier this year, analysts at Canadian investment bank RBC Capital Markets highlighted the decline in the size and capital intensity of upstream projects across the European and U.S. integrated oil and gas sector in a research note. The 24 projects green-lighted by these companies in 2017 — double the number in 2016 — were on average half the size and roughly 36 per cent less capital intensive than those sanctioned in 2013, the year before the oil price crash.

At the same time, multiple risks have made investment in Canada’s oilsands relatively unattractive to many IOCs.  These risks include a potential cap on crude oil prices at moderate levels due to the US LTO Revolution over the medium term, and possibly a substantial slowdown in oil demand growth, peak and then decline in the longer term. In addition, western Canadian oil producers have been obtaining less than world, let alone North American, crude oil prices for extended periods this decade due to shortages of pipeline capacity out of the region. Finally, there's regulatory risk, including a great deal of uncertainty about the price of carbon emissions in the future.

These risks have led a large number of IOCs to exit the oilsands over the past year and a half, selling off more than $30 billion in assets after an influx of roughly $45 billion of foreign capital the previous decade. Super-majors such as Royal Dutch Shell are believed to have sold at roughly 60 cents on the dollar. These deals have made Alberta’s oilsands industry decidedly Canadian.  The Big Four oilsands producers now include Canadian Natural, Suncor, Cenovus and Imperial Oil (in which ExxonMobil holds roughly 70 per cent).

In its latest annual outlook, released in June of last year, the Canadian Association of Petroleum Producers (CAPP) forecast oilsands production to increase 1.27 million bbls/d to 3.67 million bbls/d between 2016 and 2030. But the bulk of this incremental growth is projected in the first two and last two years, about 585,000 bbls/d and 200,000 bbls/d respectively. The 2016-18 jump is locked in — led by 80,000 bbl/d Phase 3 of Canadian Natural’s Horizon project last year, and the Suncor-led 194,000 bbl/d Fort Hills project this year — while the 2028-30 bump is suspect. CAPP is projecting the average annual increase for the relatively subdued 2019-2028 period to be less than 50,000 bbls/d.

It may be early days for development of Duvernay shale in Alberta, but it appears to have tremendous potential, with super-major Chevron referring to it as "one of the most prospective liquids-rich shale plays in North America,” when it announced a formal decision to begin commercial development at the NGLs-rich Kaybob field last November.

In addition, a September 2017 report by the National Energy Board (NEB) and Alberta Geological Survey (AGS) paints development of the Duvernay as an attractive alternative investment for companies to the oilsands region, albeit on a much smaller scale. The joint report estimates Duvernay shale to have 3.4 billion bbls of marketable crude oil and condensates and 6.3 billion bbls of NGLs — compared to 165 billion bbls of crude bitumen for the oilsands. The marketable liquids are almost half of Eagle Ford’s in Texas, while the report indicated its estimate for the Duvernay is likely “conservative,” especially for crude and condensates, given the oily eastern portion of the formation is barely explored.

On that note, Kaush Rakhit, chief executive officer of oil and gas consultancy Canadian Discovery has suggested the East Shale Basin could hold between 30 billion and 60 billion bbls of oil, with drilling costs already below $5 million per well, less than half the cost of wells in the West Shale Basin as the resource tends to be relatively close to the surface — and trending towards $4 million given continuing improvements in drilling efficiencies.

Development of the Duvernay shale formation may be in its infancy, but it could ramp up quickly based on the experience of major U.S. shale plays, and assuming the Alberta government provides an attractive fiscal regime to entice IOC investment back to the province and keep Canadian oil companies investing at home. For example, the Eagle Ford region saw exponential growth in production between January 2010 and March 2015, increasing from 55,000 bbls/d to a peak of 1.72 million bbls/d, before slipping back to 1.27 million bbls/d since the oil price crash.

But, unfortunately, the Alberta government is in a financial predicament, as the cupboard is becoming increasingly bare. Alberta’s gross debt was $33.3 billion at the end of 2016-17, compared to $11.9 billion when the New Democrats took office in 2015. Based on their own calculations, the province’s gross debt will be $71.1 billion at the end of fiscal 2019-20 and assuming the Notley government remains in office and achieves a balanced budget by 2023-24 — its target fiscal year to do so — Alberta’s gross debt will peak at $85.5 billion.

This is a big number with a big financial burden. Assuming a 3.5 per cent interest rate in 2023-24 — the same rate as implied in the latest budget for fiscal year 2019-20 — the province will have to shell out $3 billion to service our gross debt, almost four times more than the NDP’s first year in office. And interest rates, and hence debt-servicing costs, could be substantially higher for two reasons: the reversal of a 35-year downward trend in interest rates from rock bottom levels and additional downgrades to the province’s credit rating.

For this reason, the Alberta government may be reluctant to slash its fiscal take from tight oil development. But for the sake of the province and the oil industry as a whole, it needs to find a way. One possibility is a modest increase in the royalty rate for bitumen to finance a substantial cut in the fiscal take for tight oil — given the massive scale of oilsands production, its relatively limited growth prospects, and ownership of the resource now largely concentrated in the hands of Canadian-based companies.