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Canada’s unconventional oil: a bounty needing new outlets

Hemmed in by insufficient export pipeline capacity, rising output from Alberta’s vast oil sands also faces a saturated US market

The coming year for Canada’s oil industry will seem a lot like recent years. That means production will keep growing and producers will keep facing problems in finding a market for their oil. North American crude-oil prices are poised to shift to a more permanent structural discount to the rest of the world owing to the tight oil boom in the US and limited export opportunities. So oil sands producers will also be increasingly wary about prices. The lengthy permitting delays to the Keystone XL pipeline that would run between Alberta and Texas have spurred investors and politicians to take a more active approach to infrastructure development and market access, but probably too late to avoid some difficult years before export pipelines to the Atlantic and, perhaps, the Pacific come on line.

Beyond cost control, oil sands producers in recent years have faced another challenge: finding new markets. Enbridge, the carrier of about two-thirds of western Canada’s oil output, has been regularly forced to apportion capacity on some of its main lines as more and more crude is nominated to move to markets. Part of the problem has been the complexity of the Enbridge system and regulatory restrictions on operating pressures that have cut throughputs in the wake of a number of recent spills. Enbridge believes it can free up at least 200,000 barrels a day (b/d) of capacity as these restrictions are reduced and is undertaking other efforts to free up space. Some measures, such as reducing the number of grades accepted on its system, will require the support of shippers before they can be implemented.

Bakken bottleneck

Other than these operational improvements, only the expansion of the Alberta Clipper pipeline between Hardisty, in the east-centre of the province, and Superior, Wisconsin, will help reduce the bottlenecks in Alberta that are the biggest obstacles for producers. This project, which is due to be completed in mid-2014, will add another 120,000 b/d of shipping capacity on the mainline system to Superior but with oil sands output expected to rise 200,000 b/d this year, pipeline capacity will remain heavily constrained. Indeed, Enbridge expects pipeline capacity out of Alberta to be below optimal levels until 2018 given the anticipated growth in oil sands output.

Part of the problem has been the rise of the Bakken play in North Dakota. With production poised to burst through the 1 million b/d level Enbridge has been struggling to keep up with growth downstream of the oil sands. The surge in North Dakota oil output has brought new competition for markets in the Midwest, historically the endpoint for much Albertan oil, while capacity constraints in the North American pipeline network have hindered the efficient distribution of the bounty, weighing on inland crude-oil prices.

To tackle this problem Enbridge has unveiled a $4.4 billion scheme, mostly in the US, called the Light Oil Access programme that will mainly benefit Canadian conventional light-oil producers and US Bakken operators by increasing pipeline access from North Dakota to key markets like Chicago, as well as opening up opening up new markets in Ontario, Quebec, Ohio and other eastern Midwestern states by 2016. Some improvements will be ready this year. But indirectly these developments should help even Canadian heavy oil producers as they will contribute to lowering transportation costs for inland light crude and reduce pricing pressure in the Midwest. 

For those Canadian producers able to get onto the main export lines, 2014 will bring significant new marketing opportunities in the US. The conversion of BP’s Whiting, Indiana refinery to process heavy crude is nearly complete, which should boost demand for heavy barrels in the upper Midwest. At the same time, pipeline expansions will allow further penetration of markets on the Gulf Coast. The $2.8bn, 585,000 b/d Flanagan South pipeline between the Chicago area and Cushing, Oklahoma should open in mid-2014. Given that heavy crude at Cushing generally traded at a strong premium to Alberta prices even when the cost of shipping was factored in, heavy crude will be pulled south from Chicago, supporting prices further. At Cushing Flanagan South will connect with new lines to markets in Houston and Port Arthur, Texas where many refineries are equipped to handle heavy crude. Furthermore, heavy-crude demand may get a boost in Texas from the US shale oil boom as crude blenders increasingly need heavy crude to offset the very light shale oil produced from some US shale fields.

Nevertheless, getting oil from Alberta to markets in the US remains a problem. Enbridge will add another 330,000 b/d in mainline capacity for heavy crude in 2015 but beyond that there are no concrete plans for new export capacity. With the 830,000 b/d Keystone XL pipeline still in limbo, Enbridge is unlikely to commit to capacity expansions that may not be needed.

Beyond US market access, moreover, Canadian producers are increasingly determined to find a way to escape the North American market’s high transportation costs and relatively low pricing. Yet here there are considerable difficulties too. Plans to expand the existing pipeline to the Pacific Ocean, the TransMountain pipeline, are controversial, while opposition to new pipelines such as Enbridge’s Northern Gateway project – contested by environmental activists and aboriginal groups whose land is close to the nearly 1,200 km pipeline route – is considerable. The 525,000 b/d Northern Gateway project was approved by regulators in late 2013, although with a huge number of recommended changes, but must still be approved by the federal government before construction can begin. The likelihood of legal challenges means the line is unlikely to start by 2017 as Enbridge had hoped. Similarly, Kinder Morgan, the operator of the existing TransMountain line, has missed a number of self-imposed deadlines to file its expansion application with Canadian regulators. This will threaten its 2017 target for adding some 590,000 b/d to the 300,000 b/d line, especially if the regulatory process is as drawn out as it has been recently for other pipeline projects.

Given the opposition to pipelines to the Pacific, producers have agreed to back a conversion of part of TransCanada’s national natural gas transmission network to enable crude oil to be shipped to St John, New Brunswick, on Canada’s Atlantic coast. From there it would be sold to domestic refineries as well as loaded onto very large crude carriers for export.

TransCanada’s existing long-distance natural gas business has been badly damaged by the rapid growth of shale gas production in the eastern US, which has reduced demand for Albertan gas throughout eastern North America. The $12bn Energy East proposal calls for a 1.1m b/d pipeline to be constructed using, in part, surplus gas-transmission capacity, and would connect with refineries in Quebec by 2017 and the export facility in New Brunswick by 2018. Yet Energy East also faces permitting delays, with TransCanada opting to postpone filing its application with federal regulators until, at the earliest, mid-2014 amid opposition from environmental groups and a growing push by Canada’s non-oil producing provinces, including Ontario and Quebec, for transit fees.

The mounting delays with pipeline projects have led producers to start looking at other solutions. Rail, which has been a huge success in North Dakota, is an obvious alternative to pipelines but Canadian producers have been slow to embrace it given the lack of facilities available to load the large unit trains needed to keep rail shipping costs low enough for large-scale use. Construction problems delayed the start of the first facilities until late 2013 while offloading units near coking refineries in the US Gulf and in California will not be ready in large numbers until mid-2014. The derailment and subsequent explosion of a crude-oil-carrying train in the Quebec town of Lac Mégantic that killed 42 people has further complicated the development of rail shipping for Canadian oil by increasing regulatory scrutiny. This will inevitably increase the cost of shipping crude by rail.

As a result oil sands developers find themselves in a bind. Output continues to grow but market access looks increasingly fraught. The revival of US oil output has further complicated matters by saturating markets for Canadian oil in the Midwest, driving regional oil prices down. Yet the inherent advantages of the oil sands have not gone away. While the US shale boom exceeds past expectations, observers still see it as a source of incremental oil production over the next decade that should then fade away. At around 170bn barrels of recoverable oil, Alberta’s oil sands resources are, on the other hand, vast. Producers face almost no exploration risk or declines in production as fields mature. This gives operators the confidence to ride out periods of low prices, particularly as Alberta’s taxation regime remains largely favourable to producers.

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