The saga of Western Canadian producers struggling to get increasing volumes of heavy crude to market in the US has not been pretty. In 2010 the rude interruption of surging Bakken crude output competing for space on pipelines built for Canadian crude contributed to a logjam in the Midwest. Now that logjam is finally unwinding and pipeline capacity to the Gulf Coast is opening up. And Canadian producers suddenly have the option to ship bitumen crude to market competitively by rail. Today we investigate why they may be hesitating to jump on board that train.
This is the final episode in our nine part series on the development of crude-by-rail options from Western Canada to the Gulf Coast. The series started by asking whether rail capacity is needed to supplant a shortfall in pipeline space and can shipping bitumen by rail compete with pipelines on cost (see Go Your Own Way – The Rail vs. Pipeline Bitumen Challenge). We surveyed in detail the rail terminals being built in Western Canada (see Alberta Rail Load Terminals Part 1 and Part 2). Then in the fourth and fifth episodes we surveyed 8 rail terminals on the CN direct network on the Mississippi Gulf Coast. Episode six covered operating or planned terminals further east on the Texas Gulf Coast. Episode seven summarized rail load and unload capacities, which are roughly matched. In episode eight we made a cost comparison between rail and pipeline transport options.
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Western Canadian Bitumen Crude Transport Options
Most crude travels by pipeline once adequate capacity is developed. But the raw bitumen produced in Canada from oil sands is dense and treacle like, and it does not flow at room temperature. Bitumen is either mined at the surface or extracted “in-situ” by heating the well with injected steam so that the oil flows. More than half of all extracted bitumen is then upgraded to synthetic crude oil (SCO) that can be transported just like any conventional crude. The majority of mined bitumen is upgraded. The percentage of SCO is falling because the economics of upgrading are not good. Most new production is in-situ – about 90 percent of which is not upgraded. Transporting this non-upgraded bitumen to market via pipeline requires mixing it with lighter hydrocarbon solvents such as natural gasoline or condensate (known as diluents). To move bitumen on a regular pipeline typically requires blending in 28 percent diluent to create a crude known as “dilbit”. Dilbit flows easily enough year round to allow it to be pumped through a pipeline.
The trouble with dilbit is that refiners don’t like the resulting crude blend because it has too many light hydrocarbon components that they do not typically need (see Turner Mason and the Goblet of Light and Heavy). The result is that the diluent used to move bitumen is considered a “mule” that has to be procured – often from far away (see Fifty Shades of Eh?) and adds to the volume shipped without adding to the real payload. Nevertheless conventional wisdom has assumed that pipelines are the only way to ship crude long distance overland and so heavy crude bitumen is blended with diluent and shipped to market as dilbit.
Canadian Producer Travel Sickness
Canadian crude production expanded steadily over the past decade – up by 1 MMb/d from 2.5 MMb/d in 2003 to 3.5 MMb/d in 2012. The majority of that increased production is heavy crude from Western Canada. With limited local demand the obvious market was exports to the US. And initially expanding Canadian production was sent by pipeline to Midwest refiners, many of who invested to reconfigure their refineries to handle heavy crude. As Canadian production began to exceed Midwest refining capacity, plans were made to expand pipeline capacity out of Canada all the way to the Gulf Coast (e.g. the Keystone XL pipeline). Gulf Coast refineries were already processing heavy crude from Venezuela and Mexico and as those volumes declined, Canadian heavy crude was expected to be an ideal replacement.
However before all the new pipeline capacity to deliver Canadian crude to market could be permitted and built, events south of the border threw a wrench into the plans. Events in the shape of a dramatic renaissance in US domestic crude production – particularly in the North Dakota Bakken play. Bakken production was only 187 Mb/d back in January 2009, but by January 2012 it had leapt to 546 Mb/d. That surging production was all headed for the same Midwest refining market that Canadian crude was feeding – on the same pipelines. The result was a logjam of crude congestion and a huge stockpile at Cushing, OK that lasted three years from the fall of 2010 until earlier this year (2013).
During those three years Canadian producers (and their US counterparts in North Dakota) had to endure steep price discounts for their crude because there was no available incremental pipeline capacity to deliver supplies past the Midwest logjam to the Gulf Coast (see Sailing Stormy Waters). Canadian producer frustration was compounded by delays in pipeline permitting and they could be forgiven for believing that US policymakers were fitting them a new axle.
But over the past few months since April of this year, the pipeline congestion has eased as new capacity has come online and Bakken producers found other routes to market using rail transportation. By early next year even more new pipeline capacity from Cushing to the Gulf Coast (Seaway expansion, Keystone Gulf Extension), will open up to allow significant volumes of Canadian heavy crude to flow to the Gulf Coast.
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