Every gas storage injection season gives us a chance to size up how supply and demand components might influence how much gas can be stuffed away in underground reservoirs prior to the next heating season. For the Canadian storage injection season that is just getting underway, a number of factors have shifted that balance, resulting in a slowing rate of gas storage builds this year. A slower build, and subsequently lower storage levels by the end of the injection season than last year, seems likely to provide solid support for Canadian gas prices. Today, we review the latest developments and outlook for gas fundamentals in Canada.
Posts from Martin King
Corporate mergers and asset acquisitions are the normal course of business in almost any industry, but the pace of this kind of activity has recently picked up among Canada’s natural gas producers. Battered by several years of low prices, market share loss, and declining production, the position for many already-struggling gas producers only got worse when COVID hit last year. As you might expect, better placed and stronger gas producers are looking at struggling companies that have attractive assets to see if they might make accretive asset purchases or outright corporate takeovers. Today, we examine some of the most prominent natural-gas-related transactions and the motivations behind them.
Production of synthetic crude oil that is processed from Alberta’s oil sands reached record highs at the end of 2020 after touching on two year lows just four months earlier. However, these highs could be undermined and sink to four-year lows for a short period of time this spring with what appears to be a heavier than usual slate of maintenance work on three of Alberta’s four upgraders, the immense processing units that produce synthetic crude oil from bitumen. In today’s blog, we take a closer look at the upgraders, the timing of maintenance, and what this might mean for synthetic crude oil production and exports.
Last summer, Alberta natural gas prices staged a remarkable turnaround from the dismal lows and extreme volatility experienced the prior three summers. The price rise is widely credited to a temporary gas flow mechanism put in place by the operator of Alberta’s gas pipeline grid to combat congestion and oversupply issues associated with construction and maintenance during the summer of 2020. However, this temporary mechanism was just that — temporary — and will not be reinstated this summer. Without it, there is concern among Western Canadian gas producers that the weakness and volatility in gas prices seen during past summers might return this year. With warmer weather on the horizon, today we consider these issues and the potential for renewed price weakness in the Alberta natural gas market this year.
Many countries like to talk about energy independence, but Canada is one of the few to come close to that elusive goal. For many years, Western Canada has produced more than enough crude oil to satisfy the demand of refineries in the region. More recently, a combination of rising Western Canadian oil production, and new and reworked pipelines, has enabled many of Canada’s eastern refineries to increase their intake of Western Canadian barrels. In the few remaining cases where they can’t, imported barrels from the U.S. have filled the gap, leaving crude imports from overseas accounting for just 1% of the market. Not surprisingly, Canada is also a net exporter of refined products, with refiners in Western Canada, and especially Atlantic Canada, producing far more than the country’s demand. Today, we conclude our series on Canada’s refining sector with a look at its growing reliance on Western Canadian crude oil and its ability to meet most of Canada’s need for gasoline and distillates.
Canada, like the U.S., is in the enviable position of having vast crude oil reserves as well as a robust domestic refining sector capable of satisfying national needs for gasoline, diesel, and other petroleum products. Refiners in both countries have also benefited in recent years from increasing oil production within their borders. Growth in the Alberta oil sands in particular has given refineries in both Western and Eastern Canada increased access to domestically sourced bitumen and upgraded synthetic crude oil. Today, we continue our series on Canada’s refining sector with a look at the refineries in the eastern half of the nation, and their increasing use of Canadian oil.
The February 2021 polar vortex will be one for the natural gas record books in the U.S. and Canada — and the month isn’t even over yet! Though no stranger to frigid weather, Canada’s natural gas market has felt the impacts of this month’s extreme cold on both sides of the border. Its own prices, demand, and storage withdrawals have reached multi-year or all-time records as gas buyers have jockeyed for molecules from anywhere they can get them. Gas exports to the U.S. have reached highs not seen for more than a decade, adding emphasis to what has been an emerging turnaround story for Canadian gas into the U.S. market. To top things off, the latest gas market records might be a preview of what is to come in the next few years as Canada’s structural demand for natural gas continues to increase, regardless of how cold it is. Today, we describe all the latest Canadian gas market action and what might be in store for next winter.
Long established as an oil-producing region, Western Canada has also become a major producer of refined products. With enough oil available to serve the nine refineries in the region, there is no need to import crude oil, making Western Canada one of the few parts of the world where the refineries are completely self-sufficient regarding oil supply. The region is also noteworthy in that, like the U.S. Gulf Coast, its refining capacity and gasoline, diesel, and jet fuel output is vastly greater than its own demand, resulting in a large surplus of refined fuels that can be sent across Canada and exported to the U.S. Today, we look westward, focusing on the nine refineries located in the Canadian West.
Canada may be the land of backyard hockey, lacrosse, and loonies, but Canadians have many similarities to folks in the U.S. The same holds true for Canada’s refining sector, which like its American counterpart has been adjusting to big changes in domestic crude oil production, a declining need for imported oil, and, most recently, a period of severe refined-product demand destruction caused by the pandemic. What Canadian refiners lack, though, is the attention they deserve. After all, nearly 2 MMb/d of crude oil flows through their 17 refineries. And, by the way, they now turn to U.S. producers for virtually all their oil imports — a far cry from where things stood before the Shale Era. Today, we kick off a three-part series that examines Canada’s refining sector in greater detail.
Western Canada’s crude oil production, like in many other regions of the world during the spring of 2020, had to pull back sharply in response to the price and demand chaos brought about by COVID-19. By the end of 2020, oil production almost everywhere remained much lower or was being carefully managed to avoid creating another supply glut. In contrast, production in Western Canada has almost fully rebounded, and is being primed to increase to what could be all-time highs this year. With Alberta’s oil sands producers renewing their role as the long-standing driver of oil supply growth and the recent suspension of production limits in the province, the stage is set for us to review the most recent oil supply developments and future growth prospects.
Canada’s natural gas market has been a source of tremendous interest to us at RBN. Last year, demand for gas in Alberta’s oil sands sector plummeted, inventories experienced record highs, yet prices remained remarkably healthy. But how can we know all that? From a data perspective, Canada’s natural gas landscape can be confusing and frustrating. Different units of measure and currencies, limited or no data coverage for important fundamental components, and numerous statistical agencies that organize and report the data in different ways just create further complications. But this data still needs to be tracked given the impact that Canadian gas production, demand, and storage levels can have on the U.S. market — and vice versa. Having all that vital Canadian gas data in one convenient package, along with some great analysis, sure would make life easier. Today, we discuss recent developments on the Canadian gas data front and why Canadian NATGAS Billboard would be a worthy addition to your analytic needs. Warning! Today’s blog is a blatant advertorial for an RBN product.
Canadian natural gas storage levels finished the most recent injection season at a record high. With what has been a fairly mild start to the heating season so far in North America, you might be tempted to think that Canadian storage levels would have been slow to draw down. On the contrary: so far, gas is being withdrawn from storage more quickly than might be expected from the winter weather alone, partly because of structural developments that have been emerging in the Canadian market. And these changes will help to draw storage levels down closer to historical averages by the end of the current heating season in March 2021. Today, we consider these structural changes and what the current heating season might have in store for the Canadian gas market.
As bitumen production in Alberta’s oil sands has grown over the past decade, so has demand for diluent, which is blended with molasses-like bitumen to help it flow through pipelines or be transported by rail. With bitumen output expected to continue rising through the first half of the 2020s, we have estimated that Alberta demand for field condensate, natural gasoline and other diluent will increase by more than 40% — to almost 1 MMb/d — by 2025. The catch is, diluent production in Western Canada isn’t growing fast enough to keep pace, and there are limits to how much diluent can be imported on the two existing pipelines from the U.S. What if there were a way to slash how much diluent is needed to put bitumen in rail tank cars — and make rail transport safer in the process? Today, we discuss Gibson Energy and US Development Group’s new diluent recovery unit in Hardisty, AB.
The energy world has been turned upside down in 2020 by COVID-19, resulting in the cancellation, scaling back, or deferral of numerous pipeline projects in both the U.S. and Canada. One such deferral involved a planned NGL pipeline that would run through the heart of Alberta’s Montney and Duvernay plays. Originally slated to begin construction earlier this year, a one-year deferral was announced back in May by the joint venture of Canadian midstream players Keyera and Energy Transfer Canada, the latter of which is itself a JV of Energy Transfer and KKR. Since then, a stabilization in energy markets and signs of recovery in Alberta NGL production has provided the co-developers with the confidence to commit to a construction start in 2021. Today, we review the project and what has changed to get it back on track.
Petrochemicals form the backbone of modern consumer society. They provide the plastics and other materials needed to make most of the products we depend on, everything from computers and cellphones to car tires and fertilizer — not to mention N95 masks and other personal protective equipment. Petrochemicals come from crude oil, natural gas, and/or NGLs like ethane and propane, of course, and a good way for an energy-producing area to add value to its raw hydrocarbons is to develop petchem plants nearby. Alberta, Canada’s leading energy-producing province, is making a new push to encourage such projects. Today, we discuss the latest provincial program and what it hopes to accomplish.