Who Wants Alberta’s Crude Oil, Anyway?

There are some good reasons why Eastern Canadian refineries are hesitant to upgrade their facilities to handle Alberta's oil

February 20, 2017

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Why on Earth do we—the world’s fifth-largest oil and gas producing nation—import crude from the Middle East, the U.S. and Africa? It’s a question that gets asked frequently, and at first glance it seems like a no brainer—just build a pipeline to get Western Canadian oil to Eastern Canadian refineries and swap out the foreign imports.

But from a refiner’s point of view it isn’t that simple. Refining Canadian heavy crude requires billion-dollar coker units and other refinery upgrades, and ties a refiner to the market demand for Canadian oil for the foreseeable future.

These are just a few of the pros and cons refiners face when deciding whether or not to shop local.




Building a coker unit is not just a question of economics. It’s also a political question. There’s geopolitical risk associated with importing foreign oils. In Africa and the Middle East, armed insurgents routinely attack and seize energy infrastructure and destabilize national governments. The Americas don’t guarantee the security of assets either: Venezuela is on the edge of a full social meltdown and its crude exports are tanking accordingly. Mexican nationalism kept foreign investment and technology out of that country for so long that its oil and gas production has failed to reach the potential of a modern industry. Even Uncle Sam has bouts of resource nationalism, banning oil exports in the past and electing a new president who sees trade with his neighbors as an economic threat. In contrast, Canadian pipeline operators can lock in long-term contracts with reliable Canadian suppliers.

Building a bitumen coker unit in Montreal or Saint John largely assumes that TransCanada’s 1.1 million b/d pipeline will get built. That may never happen. Furthermore, for TransCanada to actually build the pipeline means it has to be certain that there is a final market for bitumen—and a single 30,000 b/d coker doesn’t deliver that guarantee. If only one Eastern Canadian refinery is upgraded to handle western crude, then TransCanada needs to sell bitumen into the Atlantic market, where the nearest oil import terminals are on the U.S. Gulf Coast. That’s the same market that almost all Western Canadian oil production already supplies via pipelines. Both Ottawa and Washington are fickle pipeline proponents—depending on who says what when in opposition and what they actually do when in power. Taking a final investment decision on a multibillion-dollar project that will last decades, while politicians remain subject to four-year election cycles, requires skillful political risk assessment.


A federally imposed carbon price—whether it’s Trudeau’s or that of a future government—could also favor the economics of investing in an upgrader to refine Canadian oil at home. A carbon tax could be levied against ocean-transport emissions, either at Canadian ports or their foreign points of origin. If Canadian carbon pricing also waived the transport tax for crudes such as Alberta’s that had already paid a carbon levy, it would hike the cost of feedstock from countries such as Nigeria that have massive pollution profiles. Such solutions are still very much up in the air as the details of Canada’s carbon plan develop.

The future of carbon price imports: UNKNOWN

Currently, the only Canadian crude oil that pays a carbon price is Alberta’s, and the provincial NDP government is committed to raising those costs. In addition, Ottawa will soon impose a carbon price that will reach $50 per ton by 2022—a cost that might not be applied to imported crudes at all or to the same degree. Furthermore, upgraders are big carbon emitters and mitigating options such as carbon capture and storage are expensive. Importing oil from countries that have no carbon pricing policies—and whose oil producers fly under the radar of Canadian environmental protesters—is still good for the refiner’s bottom line.

The price of carbon: $50 per ton by 2022


Rail transport costs more than pipeline transport. Rail is also less safe and emits more greenhouse gases, two factors which could trigger future cost-increasing regulations. Another uncertainty is that Canadian crude competes against other commodities, including coal, ore and grain for space on the rails, which drives up prices. So if Energy East is built, Albertan crude becomes more attractive. Depending on the origin and destination of crudes, the differential between North American rail and pipeline transport is typically between $5 and $15 per barrel, which can be a make-or-break spread when oil prices are low.

Tanker transport costs are still lower than pipelines. Therefore, even if Energy East is built, imported overseas crudes will always have a built-in cost advantage. So-called Very Large Crude Carriers (VLCCs) and Ultra Large Crude Carriers (ULCCs)—carrying up to two million barrels—are still the most economical method to deliver crude oil to Eastern refineries. This fact is highlighted by the economics of shipping diluted bitumen, which requires 30 percent diluent in the pipeline to move it. Diluent would likely be sold at a discount in the east compared to the west and Energy East doesn’t include plans for a return pipeline to recycle it.


The money that refiners make off the differential between the price of crude and refined products is a thin margin. The refining capacity in the east is satisfied mainly by light, high-quality oil imports, while most of Alberta’s bitumen heads south. Irving Oil and Suncor Energy are both looking at adding desulfurization units, hydro treaters and cokers to their refineries in Saint John and Montreal, respectively, in order to handle lower-cost bitumen and conventional heavy Canadian crudes. Such upgrades would change their refining economics, widening the crack spread by lowering feedstock costs. But adding a single 30,000 b/d coker unit costs something north of $1.5 billion. The Suncor and Irving refineries both lie on the path of the proposed Energy East pipeline and so their investment decisions would be based on the assumption that Albertan bitumen will remain a plentiful, low-cost feedstock with reliable producers for decades to come.

$1.5 billion Cost of a 30,000 b/d coker

Canada’s eastern refiners could wind up competing for Albertan crude against European and Asian refiners. Any access to a market that pays a premium will drive up the price for eastern refiners. Western Canadian Select sells at a discount in North America to similar crude blends in Asia and Europe where the producer gets a higher netback. Albertan crude reaching coastal terminals will rebalance the local markets, potentially making refining margins slimmer and slimmer. In addition to higher market prices around the Asia Pacific region and possibly California, there’s also energy-hungry China to take into account. It has invested $50 billion in Canadian energy projects, including oil sands stakes and pipeline infrastructure, to get crude oil to tidewater—Chinese tidewater. A handful of highly determined state-owned companies are playing a long-term energy security game, which is based less on the bottom line than on getting oil on ships back to the Chinese mainland no matter the cost or the distance required.

$15-$30/bBl The change in discount of WCS against WTI in past two years

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6 Responses to “Who Wants Alberta’s Crude Oil, Anyway?”

  1. Earl Richards says:

    The toxic, tar sands have to be refined into synthetic crude oil in the tar sands regions to prevent another Enbridge, Kalamazoo River disaster from happening again and to create jobs for Canadians.

  2. Mike Priaro says:

    There is no need to build a coker at Suncor’s Montreal refinery as this article implies.

    Alberta Oil reported on on Jan. 21, 2015 that “A coker currently sits on the site, protected from the elements, as it has since before Suncor acquired PetroCanada.”

    It’s only necessary to install it, and make any refinery revamps necessary to accommodate it. With Line 9 now reversed and shipping Alberta heavy crude to Montreal, this project should be a go.

    It would add a reported capacity of 40,000 bbl/d for Alberta heavy crude at a cost in the neighbourhood of one billion.

    • Daniel Ardeline says:

      Thank you, I didn’t know. I also suspect that 99% of Ontario and Quebec residents don’t know what a cracker or a coker is.

  3. Mike Priaro says:

    “If only one Eastern Canadian refinery is upgraded to handle western crude, then TransCanada needs to sell bitumen into the Atlantic market, where the nearest oil import terminals are on the U.S. Gulf Coast.”

    Not true.

    The sea distance from the Saint John Canaport to Port Arthur on the Gulf Coast is 2,235 nautical miles. Irving recently bought a small refinery in Cork Ireland. The distance from the Strait of Canso Superport to Cork, Ireland is 2,177 nautical miles.

    And the distance from the Strait of Canso Superport to the Come-By-Chance refinery is only 365 nautical miles.

    I suspect there is also a very good chance Irving Oil will revive the shelved 300,000 bbl/d expansion of its existing 300,000 bbl/d refinery in Saint John and install heavy crude capacity when Energy East is complete. Irving supplies refined products to a captive market in the US northeast.

    The real market for any remaining unprocessed crude delivered by Energy East will be in Europe, and western India which is eager to obtain Alberta heavy crude, not the US Gulf Coast, loading at the Strait of Canso Superport from an extension to Energy East.