Canadian crude oil production has reached highs and is expected to continue growing. But, in an area where steep price discounts have been a frequent problem, and in a world that is seemingly awash in crude, what does that mean for Canadian producers, and how will all this supply get to market?
U.S. fuel supplier Sunoco announced in May that it has inked a US$9.1-billion agreement to buy Canada-based Parkland Corp., a move that would create the Americas’ largest independent fuel distributor. Sunoco would gain control of Parkland’s fleet of fueling stations and its valuable Burnaby refinery near Vancouver, BC. The deal is supported by Parkland’s largest shareholder and is slated to be voted on June 24. In today’s RBN blog, we’ll discuss this deal and what it means for Canada’s only West Coast refiner.
It has been 12 months since the Trans Mountain Expansion Project — aka TMX — finally began operations after years of delay, creating a much-needed, larger conduit to move Western Canada’s rising crude oil production to the Pacific Northwest and overseas markets. Although the customer base for exports remains limited, the Trans Mountain pipeline system has been responsible for opening up entirely new markets for Canadian crude. As we discuss in today’s RBN blog, despite its numerous delays and immense cost, the pipeline has recently seen record crude shipments and is nearing its nameplate capacity, driven by rising exports.
After a decade-long odyssey and a cost-per-mile that must make public-sector accountants in Ottawa wince, the Canadian government-owned Trans Mountain Expansion Project (TMX) — which nearly tripled the capacity of the original Trans Mountain Pipeline (TMP) from Alberta to the British Columbia (BC) coast — finally came into service in May 2024. As one of Canada’s most anticipated energy infrastructure projects in many years, the 590-Mb/d TMX pipeline — built alongside the long-standing 300-Mb/d TMP — was widely touted by its advocates as a surefire way to boost exports of Western Canadian crude and reduce the nation’s near-complete reliance on exporting crude oil to — and through — its primary customer, the U.S. In today’s RBN blog, we discuss some of the surprising (and not so surprising) market developments since the expansion project started.
The Enbridge Mainline, by far the largest transportation network for growing Western Canadian crude oil supplies to the U.S. Midwest, Gulf Coast and Eastern Canada, recently received regulatory approval for the tolls that it charges shippers for using the massive pipeline system. As we discuss in today’s RBN blog, the Canada Energy Regulator’s (CER) thumbs-up ensures another five years of shipping cost predictability and comes as the Canadian oil pipeline landscape is about to permanently change with the pending startup of the 590-Mb/d Trans Mountain Expansion Project (TMX).
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.
Since the start of this year, Canadian heavy crude oil prices have been steadily improving relative to the light crude oil benchmark of West Texas Intermediate (WTI). Improved access to and through the U.S. as far south as the Gulf Coast has contributed to these better conditions. At the same time, the traditional driver of increasing refinery demand after the end of the most recent maintenance season is being aided by the restart of two Midwest refineries that have typically been consumers of Canadian heavy oil. With international competitive pressures also easing and export buyers remaining active in the Gulf Coast, heavy oil prices could remain in a sweet spot for a good portion of this year. In today’s RBN blog, we look at why international competition for Canadian heavy crude will only intensify next year as vastly increased export access from Canada’s West Coast becomes available.
It seems that, once again, Canada is struggling to build crude oil pipeline export capacity fast enough to keep pace with production growth. The latest setback came with the announcement that completion of the Canadian government-owned Trans Mountain Expansion (TMX) will be delayed until the third quarter of 2023 and that the 590-Mb/d project will cost almost twice as much as previously estimated. The latest six-to-nine-month delay appears to set the Canadian oil industry on a path to exhausting its spare export capacity by later this year. And that’s not good news for producers. In today’s RBN blog, we consider this latest TMX announcement and what it might mean for pipeline constraints and heavy oil price differentials.
Trans Mountain Pipeline, the only pipeline that connects crude oil production areas in Alberta to Canada’s West Coast and the U.S. Pacific Northwest, has started to resume operations after a three-week shutdown. The pipeline closure — the longest in TMP’s 68-year history — began November 14 after major flooding exposed portions of the 300-Mb/d conduit, which also carries some refined products. Fortunately, Trans Mountain did not suffer any severe damage, breaks, or spills, and its operators were able to initiate a phased restart on December 5 at reduced pressures. Full service is expected to be restored soon. So what happens when a primary source of crude oil to five refineries — four in Washington state and one in British Columbia — is removed from service with little notice? In today’s RBN blog, we discuss the impacts.
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.
