Buoyed by record crude oil flows and the expectation of further growth in Western Canada, Enbridge has been sanctioning more pipeline expansion projects and discussing plans to add more capacity.
A few months ago, Enbridge unveiled its plans to expand its massive Mainline and smaller Express/Platte crude oil pipeline systems into the U.S. Midwest/Great Plains. We blogged about those plans, and followed up with a look at how the incremental volumes of Western Canadian crude on the Mainline and Express/Platte might move south from PADD 2 to where they’re wanted most: the Gulf Coast. In today’s RBN blog, we discuss efforts to piece together a more direct pipeline route from Alberta to Cushing and on to the Texas/Louisiana coast.
Western Canadian crude oil production is rising fast. To keep pace, Enbridge is planning expansions to its pipelines into the Midwest and Great Plains. But PADD 2 refineries are maxed out on heavy crude, so virtually all those incremental barrels will need to keep flowing south to refineries and export terminals along the Gulf Coast. Can the pipelines from PADD 2 to PADD 3 handle the higher volumes? In today’s RBN blog, we discuss the knock-on effects of rising Western Canadian production and Enbridge’s pipeline expansions.
Western Canada’s Trans Mountain Expansion Project, better-known as TMX, has experienced more than its share of setbacks over the past 10 years: environmental protests, legal challenges, financing issues, an ownership change, and even a serious flooding event in 2021. But it seems the 590-Mb/d expansion of the now-300-Mb/d Trans Mountain Pipeline (TMP) system will finally become a reality by early 2024, enabling large-scale exports of Alberta-sourced crude oil to Asian markets. There’s a catch, though. The project’s long delays and other issues resulted in massive cost overruns that are now being reflected in the preliminary tolls for the soon-to-be-combined Trans Mountain system. The proposed toll increase is so large that it will cost a similar amount to ship heavy crude oil to tidewater on Trans Mountain as it would on the competing Enbridge system to the U.S. Gulf Coast for “re-export,” despite the latter being three times the distance. In today’s blog, we discuss the history of the Trans Mountain expansion, its cost overruns and the calculations that went into the proposed tolls — the kicker being that those tolls could end up being even higher.
Late last month, the Canada Energy Regulator (CER) ruled against Enbridge’s proposal to convert as much as 90% of the capacity on its multi-pipeline, 3-MMb/d Mainline crude oil system to long-term contracts. The CER’s action leaves in place the Mainline’s current capacity-allocation process, under which every barrel-per-day of the pipeline system’s capacity is open to all shipping customers on a month-to-month basis. Although the rejection of Enbridge’s proposal is unlikely to change the volume of Western Canadian crude oil flowing on the Mainline over the next few months, the longer-term outlook for Mainline flows is less certain given that other, competing pipeline capacity out of Alberta will be coming into service by late 2022 or early 2023. In today’s RBN blog, we examine the decision to reject long-term contracting and what might be the next steps for Enbridge.
The energy industry in North America is in crisis. COVID-19 remains a remarkably potent force, stifling a genuine rebound in demand for crude oil and refined products — and the broader U.S. economy. Oil prices have sagged south of $40/bbl, slowing drilling-and-completion activity to a crawl and imperiling the viability of many producers. The outlook for natural gas isn’t much better: anemic global demand for LNG is dragging down U.S. natural gas prices — and gas producers. The midstream sector isn’t immune to all this negativity. Lower production volumes mean lower flows on pipelines, less gas processing, less fractionation, and fewer export opportunities. But one major midstreamer, Enbridge Inc., made a prescient decision almost three years ago to significantly reduce its exposure to the vagaries of energy markets, and stands to emerge from the current hard times in good shape — assuming, that is, that it can clear the major regulatory challenges it still faces. Today, we preview our new Spotlight report on the Calgary, AB-based midstream giant, Enbridge, which plans to de-risk its business model.
In observance of today’s holiday, we’ve given our writers a break and are revisiting a recently published blog on our last Spotlight Report on Enbridge, Inc. If you didn’t read it then, this is your opportunity to see what you missed! Happy Thanksgiving!
The energy industry in North America is in crisis. COVID-19 remains a remarkably potent force, stifling a genuine rebound in demand for crude oil and refined products — and the broader U.S. economy. Oil prices have sagged south of $40/bbl, slowing drilling-and-completion activity to a crawl and imperiling the viability of many producers. The outlook for natural gas isn’t much better: anemic global demand for LNG is dragging down U.S. natural gas prices — and gas producers. The midstream sector isn’t immune to all this negativity. Lower production volumes mean lower flows on pipelines, less gas processing, less fractionation, and fewer export opportunities. But one major midstreamer, Enbridge Inc., made a prescient decision almost three years ago to significantly reduce its exposure to the vagaries of energy markets, and stands to emerge from the current hard times in good shape –– assuming, that is, that it can clear the major regulatory challenges it still faces. Today, we preview our new Spotlight report on the Calgary, AB-based midstream giant, Enbridge, which plans to de-risk its business model.
Enbridge’s proposal to have crude oil shippers on its now fully uncommitted Mainline sign long-term contracts for as much as 90% of the 2.9-MMb/d pipeline network’s capacity is a big deal — and controversial. Refiners and integrated producer/refiners generally support the plan, which is now up for consideration by the Canada Energy Regulator, while Western Canadian producers with no refining operations of their own — and, for many, no history of shipping on the Mainline — mostly oppose it. What’s driving their contrasting views? It’s complicated, of course, but what it really comes down to is that everyone wants to avoid what they see as a bad outcome. Refiners and “integrateds” fear that if the current month-to-month approach to pipeline space allocation remains in place, cost-of-service-based tariffs on Mainline will soar when new takeaway capacity is built on the Trans Mountain and Keystone systems and fewer barrels flow on Mainline. Producers, in turn, are wary of making multi-year, take-or-pay commitments to Enbridge if they’ll soon have other takeaway options, and are equally concerned that they’d be left in the lurch if they don’t commit to Mainline and the Trans Mountain Expansion and Keystone XL projects don’t get built. Today, we consider both sides of this important debate.
Up in Canada, there is finally a regulatory timeline for reviewing Enbridge’s long-standing proposal to revamp how it allocates space — and charges for service — on the company’s 2.9-MMb/d Mainline. But the plan to convert the largest crude oil pipeline system out of Western Canada from one whose space is 100% uncommitted and allocated every month to one with 90% of its capacity locked in via long-term contracts remains controversial, especially among producers. Plus, the world has changed in the past few months. Oil sands and other production in Alberta and its provincial neighbors is off sharply in response to pandemic-related demand destruction and low oil prices, and the always-full Mainline has been running at well under 90% of its capacity lately. Further, the Trans Mountain Expansion and Keystone XL projects — competitors to the Mainline in a way — have progressed this year, making shippers wonder whether to lock in capacity on the Mainline if TMX and KXL’s completion may be imminent. Today, we begin a short series on the prospective shift to a contract-carriage approach on the primary conduit for heavy and light crudes from Western Canada to U.S. crude hubs and refineries.
By mid-year, Enbridge plans to initiate an open season for long-term, firm capacity on its existing 2.8-MMb/d Mainline crude system from Western Canada to the U.S. Midwest starting in mid-2021. Securing a sure way for Western Canadian heavy-crude producers to export crude from the Alberta oil-sands region — combined with additional southbound pipeline capacity from the Midwest to the Gulf Coast, would give Texas and Louisiana refineries an alternative to using overseas imports and would boost crude volumes being shipped from existing and planned export terminals. Today, we conclude our series on the pipeline’s contracting plans with a look at the impact of a straight-shot, joint-tariff pipe as well as joint pipe-barge transportation solutions from the oil sands to the Gulf Coast.
