Production in Alberta’s oil sands region is gradually rebounding after devastating wildfires that forced output scale-backs and temporary shutdowns of some production facilities, terminals and pipelines. It may be a while before life—and production—in the oil sands are back to normal, but Canada’s National Energy Board, producers and others expect the region’s output to continue to rise (if only gradually) the next few years, reflecting long-term oil sands expansion projects committed to when oil prices were more than double what they are today. There are very different views, though, about whether the oil sands will eventually need more takeaway capacity in the form of new or expanded pipelines. Today, we continue our look at the oil sands post-wildfires with a review of existing and proposed pipeline capacity.
Wildfires are notoriously unpredictable and, sure enough, as soon as the worst seemed to be over in the Fort McMurray, AB area, new flare-ups in mid-May threatened oil sands production areas north of the city. Thanks to heroic efforts by Alberta fire crews, no production area has experienced any significant damage (so far at least—fingers crossed), but a few work camps have been destroyed or damaged, and will need to be rebuilt. Good news is trickling in though, such as Imperial Oil’s May 19 announcement that it has restarted limited operations at its Kearl oil sands site. If, as everyone hopes, the wildfires are brought under control within the next few days, it seems likely that oil sands production will ramp up gradually over the next few weeks, and that by mid-summer Alberta’s output might be close to the 3.1 MMb/d that the province was producing before the fires were sparked.
As we said in the first episode of this series, oil sands producers have been especially hard-hit by the collapse in oil prices, for four main reasons: 1) their hydrocarbon-extraction process is more complicated and costly than their shale-play counterparts; 2) the oil sands are farther away from most major refinery centers than most U.S. shale plays; 3) oil sands producers need to either add diluent to their bitumen to allow it to flow through pipelines, or transport low-viscosity bitumen in special “coil” rail cars that can be heated before unloading; and 4) existing pipelines out of the oil sands to the U.S. Midwest and Gulf Coast—and the existing Trans Mountain Pipeline to British Columbia—had been bumping up against capacity limits, resulting in significant, margin-erasing price discounts to West Texas Intermediate (WTI), at least until incremental pipeline capacity started coming online in early 2015. Things are better now on the takeaway/discount front, but Western Canadian Select (WCS, the region’s benchmark mix of 19 heavy conventional and bitumen crudes blended with synthetic crudes and diluent) is still trading at about $37/bbl, or $12 below WTI, reflecting the higher cost of moving Western Canadian crude to refineries and quality differentials for heavier oil sands grades.
In this episode we’ll discuss how much oil sands production is likely to rise over the next few years and whether the region might need new pipeline takeaway capacity to help ensure that price discounts for WCS don’t start growing again. Canada’s National Energy Board (NEB) has taken an optimistic long-term view on national, by-province and oil sands production growth, predicting in two recent reports (released in January and May 2016) that (under the reference or base case) Canada’s production will rise from just under 4 MMb/d in 2015 to nearly 5 MMb/d by 2020 and to 6 MMb/d by 2040 (Figure 1), with most of the growth coming from Alberta’s in situ bitumen production (orange layer) and, to a lesser extent, from the province’s mined bitumen output (medium-blue layer). Western Canadian Sedimentary Basin (WCSB) condensate (purple layer), heavy oil (green layer) and light oil (red layer)—production of which all stay essentially flat--account for most of the rest of Canadian production. NEB sees Alberta’s oil production rising from 3.1 MMb/d in 2015 to about 4 MMb/d by 2020 no matter what happens with oil prices in the interim, and to about 5.2 MMb/d by 2040 (again, under the NEB’s reference/base case).