Enbridge is taking a serious look at converting its Southern Lights pipeline, which currently transports diluent northwest from Illinois to Alberta, to a 150-Mb/d crude oil pipe that would flow southeast. The potential reversal of Southern Lights is made possible by the facts that Western Canadian production of natural gasoline and condensate — two leading diluents — has been rising fast, and that demand for piped-in diluent from the Lower 48 is on the wane. Alberta producers could sure use more crude pipeline capacity out of the region — and getting crude down to the U.S. Midwest would give them good access to a variety of markets. With Western Canadian diluent production increasing fast, maybe Kinder Morgan’s Cochin Pipeline, another diluent carrier, could also be flipped to crude service later on. Today, we consider how Southern Lights’ conversion/reversal might help.
A common theme among major North American crude plays in 2018-19 has been crude takeaway constraints. The Permian is a prime example — see Pump It Up for a recent summary of the Permian’s takeaway woes and how they’re being addressed — but many Western Canadian producers would argue that their situation is worse, and more intractable. After all, new crude pipeline capacity between West Texas and the Gulf Coast will be coming online over the next few months, but it will be at least a year and a half before the next big tranche of incremental capacity out of Alberta will be added — Enbridge’s Line 3 Replacement Project, which will add 370 Mb/d to the company’s Mainline system (orange line in Figure 1) in late 2020. And it’s still uncertain when the Canadian government’s 590-Mb/d Trans Mountain Expansion (TMX; dashed purple line) will start up, or when TransCanada will finally get all the approvals it needs to build the 830-Mb/d Keystone XL (dashed green line). When they finally do come online, they will supplement existing takeaway on the Mainline and the Express Pipeline (yellow line), Keystone (green line) and the Trans Mountain Pipeline (purple line).
Western Canada’s crude takeaway problem is migraine-inducing. As we said in our recent Maybe It’s Time blog series, crude production in the Western Canadian Sedimentary Basin (WCSB) has increased from ~3 MMb/d in 2010 to ~5 MMb/d today, with virtually all of the incremental output available for export. Pipeline capacity from the WCSB to the U.S. has been rising too — from ~2.7 MMb/d nine years ago to ~4 MMb/d now — but not quickly enough to keep up with production gains. In 2018, with export volumes meeting and even exceeding available pipeline takeaway, there was a resurgence in crude-by-rail (CBR) volumes and a widening in the price spread between Western Canadian Select (WCS, a benchmark heavy-crude blend) and West Texas Intermediate (WTI). In November 2018, the spread grew to nearly $40/bbl, prompting the provincial government of Alberta — the center of WCSB production, including the oil sands — to institute mandatory production cuts (that started in January 2019 and have since been ratcheted down) in an effort to bring Alberta output more in line with available takeaway capacity. Takeaway concerns, depressed WCS prices and Alberta government intervention in the market all were likely factors in the mid-March decision by Imperial Oil (ExxonMobil’s Canadian subsidiary) to delay the completion of its Aspen in-situ oil sands project near Fort McMurray, AB, by at least a year, to 2023 or later.
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