Western Canadian Select (WCS), a heavy crude oil blend, has been selling for about $25/bbl less than West Texas Intermediate (WTI) at the Cushing, OK, hub — a hard-to-bear experience for oil sands producers that have made big investments over the past few years to ratchet up their output. And the WCS/WTI spread is unlikely to improve much any time soon. Pipeline takeaway capacity out of Alberta has not kept pace with oil sands production growth, and existing pipes are running so full that some owners have been forced to apportion access to them. Crude-by-rail (CBR) is a relief valve, but it can be costly. Worse yet, production continues to increase and the addition of new pipeline capacity is two years away — maybe more — so deep discounts for WCS are likely to stick around. Today, we discuss highlights from our new Drill Down Report on Western Canadian crude markets.
It hasn’t been an easy winter in Western Canada’s oil patch, and we’re not talking about the weather. Sure, production in the oil sands continues to ramp up as new projects — large and small — come online after years of development. Output from the Western Canadian Sedimentary Basin (WCSB), which includes the Alberta oil sands, now stands at about 4.0 MMb/d, and the consensus among Canadian forecasters is that production will increase to 5.0 MMb/d by 2025.
But that’s where the good news ends. A collapse in the price of WCS versus WTI that started last fall has put a spotlight on the pipeline takeaway issue: WCSB production now regularly exceeds the ability of existing pipeline networks to handle the flow. In-region storage and crude-by-rail (CBR) shipments have served as a cushion of sorts, absorbing shocks like a 12-day shutdown of the Keystone Pipeline in November 2017 and the pipeline apportionments since. But with more production gains expected in 2018-19, that cushion seems uncomfortably thin. And while new pipeline capacity is being planned by Enbridge, Kinder Morgan and TransCanada, these projects have faced regulatory and other challenges, setting back their online dates. As it stands now, no new pipeline capacity will begin operating until at least early 2020. With the oil sands’ largest greenfield mining project in years — Suncor Energy, Total and Teck Resources’ 194-Mb/d Fort Hills project — ramping up toward full production over the next year, all signs point to worsening pipeline constraints, increased use of higher-cost CBR and more double-digit spreads between WCS and WTI prices.
Of course, WCS would logically sell at some discount to WTI — it costs several dollars per barrel to transport crude by pipeline from Western Canada to Cushing, the U.S. Gulf Coast and other far-away refining centers, and several dollars more to move crude by rail. But as Figure 1 shows, the $10/bbl spread between WCS and WTI (blue line) that producers had grown accustomed to started widening a few months ago, initially to around $11-12/bbl during September and October (2017), and then — in a memorable blow-out later last fall — to around $25/bbl. It has bounced between $20/bbl and 30/bbl ever since. Note also that WCS has averaged about 55% of WTI so far this year (green line) — a paltry level only breached briefly a couple of times in the past 10 years. In other words, the price for WCS relative to other crudes is about as bad as it has been since WCS started trading as a unique crude grade.
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