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Trapped Oil – The Canadian Infrastructure Dilemma

As BTU Analytics readies our new Canadian section for the Upstream Outlook, we thought it would be timely to share some recent analysis.  Canada has been using new horizontal drilling technology to exploit shale resources in the Montney and the Duverney, however, the biggest engine of oil growth from Canada is expected to be the Canadian Oil Sands in Alberta.  In the October 2014 edition of the Alberta Oil Sands Quarterly, 49 Oil Sands projects were categorized as “approved” or were “under construction” and scheduled for completion between 2015 and 2019, totaling a capacity of 2.18 MMb/d. In the March 2015 edition, that same number fell to 1.36 MMb/d due to weakness in oil prices.  However, the number of projects and capacities under construction and expected to be completed between 2015 and 2017 has changed little since last fall.  While project delays are not out of the question, there is already 335 Mb/d of production capacity scheduled to come online this year and another 600 Mb/d under construction and expected to come online by the end of 2017.   Should the projects be completed on schedule, Canada will continue to need additional infrastructure to be built.

Oil Sands Projects

Currently, all of the pipeline routes out of Canada already full and only the Enbridge de-bottlenecking projects are set to come online before 2019.  This means that rail will play an increasingly important role in transporting Canadian crude.  The Enbridge pipeline projects, with in-service dates by the end of 2017, will only add about 650 Mb/d of incremental takeaway capacity out of Canada over the next three years, potentially leaving 280 Mb/d of planned oil sands production growth stranded, looking for another way to leave Canada.

Enbridge Mainline Flows

According to the EIA, Canadian crude by rail receipts from the US  steadily increased until reaching a peak of 151 Mb/d in November 2014 before declining to 103 Mb/d in March.  Without major pipeline projects, BTU Analytics expects that rail volumes will increase by 200 to 300 Mb/d in the near term to support oil sands production growth.

Canadian Rail Deliveries to the US

Unfortunately, rail is more expensive than pipeline transportation, lowering netbacks to Canadian producers who are already feeling pain from low oil prices. Adding to that pain, many of the pipeline projects announced to serve Canadian producers have been fighting up-hill battles to receive permit approval from the US and Canadian governments.  Keystone XL, a pipeline with 800 Mb/d of nameplate capacity was proposed back in 2012 and is still waiting for the US government to grant it approval to build across the US and Canadian border.  More recently, TransCanada announced that the lesser known Energy East pipeline conversion project with a nameplate capacity of 1.1 MMb/d was delayed from late 2018 to 2020.  This delay was announced in conjunction with the decision to find an alternate location for the Cacouna export terminal near Riviere du Loup, Quebec, which was to source oil from the Energy East pipeline project.  According to NEB permit filings, the tariffs to travel from Hardisty to Eastern Canadian refineries or a potential export terminal, range from $6.90 to $7.40 per Bbl.  This is quite a bit cheaper than moving to Eastern Canada via rail, which costs between $10 and $15 per Bbl, making this pipeline an attractive option to raise netbacks to producers.  Energy East will likely provide a competitive route for light Bakken barrels to serve the refining market in Eastern Canada as well as provide an export option to reach the global heavy oil market as well.  From an export perspective, there is demand for heavy crude in places like India and China.  However, the US has the largest heavy refining complex in the world and is a natural home for WCS.  All we need are economic transportation routes.

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Erika Coombs is Manager of Consulting Services at BTU Analytics. She leads the team to deliver customized energy-market analysis and provides BTU Analytics’ customers with critical information for a variety of energy markets including oil, gas, and NGLs from wellhead to downstream markets. She also leads research on upstream analysis, crude oil midstream infrastructure, breakeven economics, and commodity pricing dynamics for several BTU Analytics’ reports. She holds a M.S. in Mineral and Energy Economics from the Colorado School of Mines.

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