Enbridge’s 2.8-MMb/d Mainline system from Alberta to the U.S. Midwest has been running close to full, as have the other crude oil pipelines out of Western Canada. The Mainline is a unicorn among these pipes, however, in that none of its capacity — zilch — is under long-term contract. Instead, under Enbridge’s almost nine-year-old Competitive Tolling Settlement (CTS), shippers each month submit nominations stating the volumes of crude they would like to transport the following month on various elements of the Mainline system, then hope they get what they need when the available capacity is divvied up. In an effort to give producers and refiners the pipeline-capacity certainty they say they want — and to optimize the efficiency of the Mainline’s operation — Enbridge has been working with shippers on a CTS-replacement plan that would commit as much as 90% of the capacity on the pipeline system to shippers who enter into long-term contracts. Today, we continue this blog series with a look at how the prospective “priority access” capacity-allocation system is shaping up, how it might affect planned pipeline projects, and how it may facilitate the transport of a lot more crude from Alberta to the U.S. Gulf Coast.
As we said in Part 1, it’s been an interesting few years for the Western Canadian crude oil market. Since 2010, Western Canadian Sedimentary Basin (WCSB) production has increased by two-thirds — from ~3 MMb/d to ~5 MMb/d — 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, including about 2.8 MMb/d on the Enbridge Mainline (yellow capacity line in Figure 1) — but not quickly enough to keep up with production gains. (The medium-blue bars in the chart show average annual flows on the Mainline at the U.S.-Canada border from 2013 through 2017; the dark-blue bars show average quarterly flows in 2018.) Shortfalls in pipeline takeaway capacity led to super-wide price differentials between Western Canadian Select (WCS; the region’s benchmark price for heavy-sour blend) and West Texas Intermediate (WTI), which more than covered the cost of rail transport and spurred a big rebound in crude-by-rail (CBR) activity. In late November 2018, Alberta’s provincial government announced a plan to add thousands of tank cars to the regional fleet in 2019-20 to enable still more crude to be moved by rail. A few days later, in early December, the government stepped in again, mandating a nearly 9% crude-oil production cut (starting January 1, 2019). That move quickly shrank the WSC-WTI spread to the point that it brought into question whether CBR costs could still be justified; from what we’ve heard from traders and earnings calls, CBR volumes for at least a few companies fell in January. (In response to the much smaller spread, the Alberta government late last month pulled back on its mandated production cuts for February and March.) Amid these market gyrations, TransCanada and Canada’s federal government continue to face headwinds in their respective efforts to build the Keystone XL pipeline and the Trans Mountain Expansion (TMX) project — there are no firm dates for when that new takeaway capacity will come online.
What a roller-coaster. Add to this uncertainty the fact that none of the capacity on the Enbridge Mainline’s myriad pipeline segments — Lines 1, 2, 3, 4, 5, 6, 7, 10, 11, 14, 61, 62, 64, 65, 67 and 78 (did we forget any?) — is under long-term contract, so all of it is up for grabs each month. As WCSB production rose and takeaway pipelines filled up in the past few years, shippers — typically producers, refiners and/or marketers — have indicated they want the higher degree of confidence that long-term capacity contracts provide.