Crude-by-rail has saved the day for Alberta producers before, and it’s about to again. The talk of the Western Canadian province the past few days has been the Alberta government’s October 31 announcement that it will allow incremental crude oil production beyond the province’s 3.8-MMb/d cap — if that crude is transported to market by rail. Within hours of the government’s statement, a trio of major producers indicated that they now expect to ramp up their Alberta output by a total of more than 100 Mb/d over the next few months, with a good bit of the gain occurring by year’s end. Production increases from others are likely to follow, as are parallel plans to load that crude into tank cars and rail it to market. But can Alberta producers really thrive without more pipeline capacity? Today, we review recent developments in “Canada’s Energy Province” and what they mean for producers and Alberta crude prices.
In the second half of the 2010s, plans for production growth in the oil sands and elsewhere in Alberta have been stymied to varying degrees by the lack of sufficient pipeline capacity. As we said in The Shape I’m In, our spring 2018 Drill Down Report on Western Canadian crude markets, producers and midstream companies responded to these takeaway shortfalls by adding crude-by-rail capacity and by advancing a number of pipeline projects that, over time, would eliminate the constraints and enable production growth to occur pretty much unfettered. By last fall, though, production again was bumping up against, and even exceeding, the combined capacity of pipelines and railroads; crude inventories within Alberta were up sharply; and the price differential between regional benchmark Western Canadian Select (WCS) and West Texas Intermediate (WTI) had widened to an astonishing $50/bbl (navy blue line and dashed yellow oval in Figure 1), putting the cash value of a barrel of WCS at little more than $20.
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