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.
Posts from Martin King
The current winter heating season in Canada has seen extremes of warmth and cold, but much more of the former than the latter. Given that the Canadian natural gas market was already oversupplied and struggling with record-high gas storage levels as winter approached, even the most intense cold blast in mid-January wasn’t enough to return the supply/demand balance north of the 49th parallel to anything near normal. In today’s RBN blog, we discuss where the Canadian market stands as the calendar turns to February and what that might mean for end-of-winter gas balances.
The demand for ethane by Alberta’s petrochemical industry has experienced a slow expansion in the past 20 or so years. However, that demand is likely to increase sharply by the end of the decade now that Dow Chemical has sanctioned a major expansion at its operations in Fort Saskatchewan, AB, that will more than double the site’s ethane requirements. As we discuss in today’s RBN blog, this will call for an “all-hands-on-deck” approach to increasing Alberta’s access to ethane supplies from numerous sources.
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.
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.
The 590-Mb/d Trans Mountain Expansion (TMX) project, which is inching closer to its planned early 2024 completion, has been one of the most eagerly anticipated energy infrastructure projects in recent Canadian memory. Preliminary tolls for shipping crude on the expanded pipeline system, submitted to the Canada Energy Regulator (CER) in June, are multiples higher than the tolls currently charged on the original 300-Mb/d Trans Mountain Pipeline (TMP), possibly undermining oil producers’ economics for shipping and exporting crude on the combined 890-Mb/d system. However, the higher tolls are not the only concern. Serious logistical challenges remain in the form of restricted tanker sizes, a circuitous route for ships traveling from the open ocean to the Westridge export terminal near Burnaby, BC, and even a very tight passage under two bridges, all of which will add costs and time for each exported barrel. In today’s RBN blog, we provide more details on the complexities surrounding crude oil exports via the Trans Mountain pipeline system.
In natural gas markets, warmer-than-average winters usually translate into oversupply conditions as heating demand draws less gas out of storage than what would normally be expected. When compounded by rapidly rising domestic production and soft gas exports, the result is even greater oversupply. That is exactly how the Canadian gas market finished the most recent heating season, facing a substantial oversupply of gas that, if it persisted, could result in domestic gas storage reaching capacity well before the start of the next heating season. However, when it comes to natural gas markets, or any other market for that matter, expect the unexpected. Gradually improving demand and export conditions, combined with a significant decline in domestic gas production event in Western Canada, has rapidly shifted the market from substantial to slight oversupply in a matter of months. This has reduced downward pressure on prices and created conditions that might lead to a more manageable storage level before the next heating season gets underway. In today’s RBN blog, we consider what has been generating the rapid shift in Canadian gas market balances this summer.
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.
Western Canada’s natural gas production has been on a roll in the past couple of years, reaching a record 17.3 Bcf/d in 2022. Another year of strong growth was expected in 2023, but Mother Nature had other plans — as usual. First, a milder-than-average heating season left plenty of gas in storage, pushing natural gas prices lower across North America. Second, tinder-dry conditions in some of the best gas production areas in Alberta and British Columbia sparked what so far has been a very active wildfire season — and forced producers to curtail their gas output numerous times in May and June. From our early expectations for production growth of 1.2 to 1.4 Bcf/d this year, the impacts from wildfires and a healthy dose of pipeline maintenance has chopped our 2023 production growth outlook to just 0.4 Bcf/d. As we discuss in today’s RBN blog, this slowdown in growth is exactly the opposite of what’s needed to avoid a runup in prices. Strong production momentum will be required into 2024 and 2025 to deal with the startup of the LNG Canada export facility, ongoing Canadian gas demand growth and pipeline exports to the U.S.
Canada has been exporting propane from marine terminals in British Columbia (BC) to Asian markets since May 2019 and, despite modest propane production volumes, it has become an integral part of the global market — Japan, for example, depends on Canada for one-ninth of its LPG. Now, the companies that co-own the larger of BC’s two LPG export terminals are planning yet another facility next door that would enable Canadian propane exports to Asia to double over the next few years. In today’s RBN blog, we discuss the AltaGas/Royal Vopak plan and its implications for Canadian producers and LPG consumers in Canada, the U.S. and Asia.
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.
In the past, Canadian heavy oil was all too often the sick man of the North American oil market. Plagued by a limited number of refinery outlets and numerous episodes of insufficient pipeline export capacity from Western Canada, it was often subject to far larger price discounts versus the light crude oil price benchmark of West Texas Intermediate (WTI) than was justified by quality and pipeline transportation costs alone. In the past few years, however, improved pipeline export capacity to and through the U.S. has expanded the number of refineries Canadian heavy oil can reach, and the expansion of crude oil export terminals along the Gulf Coast has resulted in greatly improved exposure for Canadian barrels to buyers in international markets. The end result has been a closer alignment of Canadian heavy oil pricing in its home base of Alberta with those in the Midwest and Gulf Coast.
Though much smaller in scope than the oil-and-gas producing behemoth of Western Canada, oil production from the offshore of Canada’s easternmost province of Newfoundland and Labrador already has decades of experience behind it. With five offshore fields producing a little under 230 Mb/d as of early 2023, the region’s slow decline is likely to continue unless existing fields undertake additional development work or new fields are discovered. Building on the province’s commitment to double output by the end of this decade, it has worked with various offshore operators to enhance its royalty regime for two existing sites that will generate increased production in the next few years. In addition, one major discovery has the real potential to meet the pledge of doubling output by the early 2030s. In today’s RBN blog we consider the history of the region’s offshore oil production and future plans to increase output.