The looming threat of a 10% tariff on U.S. imports of Canadian crude oil hasn’t just angered Canadians — and understandably so, we might add. It’s also put a spotlight on PADD 2 — the Midwest/Great Plains region — whose pipelines transport the vast majority of Canadian exports and whose 25 refineries (combined capacity 4.3 MMb/d) are, in many cases, significant consumers of heavy and light crudes from up north. Put simply, to assess the impacts of the still-possible trade war on U.S. refiners and producers on both sides of the border, you need to understand PADD 2’s crude oil supply/demand balance and the options Midwestern refineries that currently run Canadian crude would have if a tariff were put in place. In today’s RBN blog, we’ll discuss these dynamics.
Oil sands
President-elect Trump’s plan to impose a 25% tariff on all imported goods from Canada and Mexico — including crude oil — has raised concern among U.S. refiners, many of which depend heavily on those imports and would face serious challenges in replacing them. The question is, given that dependence and the incoming administration’s pledge to reduce energy costs, will refiners — and oil producers in Canada and Mexico — succeed in their efforts to exempt crude oil from the tariff plan? In today’s RBN blog, we discuss the degree to which U.S. refineries incorporate Canada- and Mexico-sourced oil in their crude slates, the potentially devastating impacts of a tariff on Canadian crude in particular, and the odds for and against U.S. tariffs on oil imports from its neighbors.
The multibillion-dollar acquisitions that have become almost routine in the upstream sector the past few years are typically accompanied by asset rationalization — in other words, a thoughtful look at which elements of the pro forma company make sense followed by the divestiture of those that don’t. In many cases, a key aim of that rationalization process is trimming any debt associated with the acquisition itself. In today’s RBN blog, we’ll discuss the big steps Chevron has been taking to rework its portfolio — and sell off up to $15 billion in assets — as it inches toward closing on its $60 billion purchase of Hess Corp.
Thanks to expanding heavy crude oil production in Western Canada’s oil sands in recent years and increased pipeline access from the region to the U.S. Gulf Coast, re-exports of Canadian heavy crude from Gulf Coast terminals set a record in 2023. With additional production gains on tap in the oil sands, it might seem natural to think that another re-export record is in the works for 2024. However, assuming the much-delayed Trans Mountain Expansion Project (TMX) does indeed start up this year — offering a vastly expanded West Coast outlet for oil sands production — last year’s re-export high might end up being a peak, at least for the number of years it takes for growth in Western Canadian heavy crude production to exceed the capacity of the TMX expansion. In today’s RBN blog, we take a closer look at TMX’s likely impact on Gulf Coast re-exports.
Wider price discounts for Western Canadian heavy crude oil have been weighing on its oil producers for the past few months. This appears to be the result of a combination of weak refinery demand, rapidly rising oil production and insufficient oil takeaway capacity from Western Canada. A more permanent solution for wider discounts might be to increase pipeline export capacity to ensure that rising oil production has more options to reach markets. In today’s RBN blog, we consider the pending startup of the Trans Mountain Expansion Project (TMX) as a means to do just that.
The price discount for Western Canada’s benchmark heavy crude oil has seen yet another widening in the past few months. Increased pipeline access to the U.S. was believed to be the key to solving this problem in the long term, but more recent fundamental developments surrounding pipeline egress, refinery demand and increasing heavy oil supplies demonstrate that larger discounts can — and do — still happen. This problem could persist for several more months until a better balance is achieved in downstream markets. In today’s RBN blog, we discuss the latest drivers of the wider price discounts for Western Canada’s heavy oil.
Many governments around the world are looking for ways to incentivize reductions in greenhouse gas (GHG) emissions and two approaches have received the most attention: cap-and-trade and a carbon tax. The European Union (EU) has chosen the former, Canada has opted for the latter, and the U.S. — well, that’s still to be determined. It’s logical for oil and gas producers, refiners and others in carbon-intensive industries to wonder, what does it all mean for us? In today’s RBN blog, we look at Canada’s carbon tax (which it refers to as a “carbon price”), explain how it works, and examine its current and future impacts on oil sands producers, bitumen upgraders and refiners.
Merger-and-acquisition (M&A) activity in Canada’s oil and gas sector has accelerated this year compared to 2022. With crude oil prices generally strengthening over the course of 2023, it should come as no surprise that the focus of much of this activity has been crude oil- and NGL-producing companies and assets. As we discuss in today’s RBN blog, several large deals have been announced and many have already closed, including a complex arrangement involving Suncor and production ownership in the oil sands that only recently concluded after six months of uncertainty, with more deals expected before the year is over.
For many years now, the U.S. has been buying — and piping or railing in — virtually all of the crude oil Canada has been exporting, in part because Canadian producers have only very limited access to coastal ports. More recently, greater pipeline access from the Alberta oil sands to the U.S. Gulf Coast (USGC) has created an attractive pathway — a “Carefree Highway,” if you will — for Canadian crude oil to be “re-exported” to overseas customers. This year, much stronger international demand has sent re-export volumes to record highs — and provided Alberta producers very attractive price differentials for their oil sands crude. That overseas demand appears to be sustainable, but with the looming startup of the 590-Mb/d Trans Mountain Expansion Project (TMX), which will increase the capacity of the Trans Mountain Pipeline system to 890 Mb/d and enable much more Alberta crude to be exported from docks in British Columbia, the re-export surge from the USGC may be in for a pullback, as we discuss in today’s RBN blog.
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.
Shipping Alberta’s fast-rising bitumen production to market through pipelines or on insulated rail cars depends on sufficient supplies of diluent, a variety of light hydrocarbons that, when blended with molasses-like bitumen, reduce the viscosity of the resulting mix. The problem is, in-region production of diluent — an economically favorable alternative to pipeline imports from the U.S. — has been growing more slowly than it was a few years ago, and increased demand for imported condensate could result in those pipelines being maxed out. In today’s RBN blog, we delve into what may be behind the slowing pace of Western Canadian diluent production and what the implications might be.
Oil sands, the workhorse of Alberta’s — and Canada’s — crude oil production growth, achieved a record production year in 2021. A steady turnaround in crude oil prices, improved market access, and the tried-and-true resilience of oil sands producers combined to drive the increase in output. With 2022 barely out of the starting blocks, the oil sands players have provided production guidance for this year that, if fulfilled, could set the oil sands on track for another year of record output. In today’s RBN blog, we consider the latest production guidance estimates and what these could mean for the availability of oil pipeline export capacity from Western Canada.
With Alberta’s bitumen production rising to record levels of late, finding more ways to export this molasses-like heavy oil has become more important than ever. In early 2020, Gibson Energy and US Development Group embarked on the construction of a diluent recovery unit in Hardisty, AB, to greatly reduce the need for diluent and retain more of it for reuse. With the unit’s commercial start-up at the end of 2021, another unique pathway for transporting Canadian bitumen to the U.S. Gulf Coast — and, possibly, overseas markets — has become a reality. In today’s RBN blog, we provide an update on this venture and discuss where it might lead next.
Although it’s not well publicized, Canada’s oil and gas sector is already a global leader in active projects targeting significant reductions in greenhouse gas emissions, primarily carbon dioxide. These successes — some dating back as far as Y2K — are being used as a springboard for additional projects, all aimed at helping Canada achieve its aggressive GHG-reduction goals for 2030 and beyond. The scale of many of these projects is noteworthy. In today’s blog, we discuss the existing operations and planned projects that together will help the U.S.’s northern neighbor reduce its carbon footprint.
The U.S. and Canada make quite a team. Friends for most of the past century and a half — and best buddies since World War II — the two countries have highly integrated economies, especially on the energy front. Large volumes of crude oil, natural gas, NGLs, and refined products flow across the U.S.-Canadian border, and a long list of producers, midstreamers, and refiners are active in both nations. One more thing: since the mid-2000s, the development of U.S. shale and the Canadian oil sands in particular has enabled refiners in both countries to significantly reduce their dependence on overseas oil — a big victory for North American energy independence. However, due to its smaller population and economy, Canada typically gets far less attention than its southern neighbor, so in today’s blog we try to right that wrong by discussing highlights from a new, freshly updated Drill Down Report on Canada’s refining sector.