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.
Posts from Martin King
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 On the contrary: so far, gas is being withdrawn from storage more quickly than might be expected from the winter weather alone, partly because of structural developments that have been emerging in the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.
For most of the past few years, crude oil producers in Alberta have dealt with pipeline constraints that often forced them to sell their crude at steep discounts. While the constraints eased somewhat earlier this year as producers reduced their output due to cratering oil demand and oil prices, production more recently has been rebounding, resulting in the return of takeaway concerns. The big hope is that long-planned pipeline projects like the Trans Mountain Expansion (TMX) and Keystone XL will finally be built and commissioned, but they still face legal and regulatory hurdles before being completed. Lately, a different option has gained momentum focusing on a proposed rail line linking Alaska to the immense oil sands region of northern Alberta, potentially creating another corridor for the export of oil sands crude. Today, we describe recent developments in a bold plan to build a rail line from Alberta, across northern Canada, and into Alaska.
On December 1, the government of Alberta will officially end its nearly two-year-old policy of curtailing crude oil production to help shrink the massive price discounts that producers had been enduring. It would hardly be an overstatement to say that North American oil markets have changed dramatically since the production cap was implemented by Canada’s largest oil-producing province in January 2019. A short-but-bruising oil price war and a pandemic that slashed demand for crude resulted in Alberta producers making supply cuts even bigger than their government had mandated. Today, we look back at the provincial government’s policy and what has changed to motivate its suspension.
Natural gas production has been growing in Western Canada in recent years with an increasing share of that supply coming from core areas of activity within the Montney and Duvernay plays. This tighter focus has forced TC Energy to rework and expand its giant Nova Gas Transmission Limited pipeline system, a network that originally gathered gas supplies across a much larger geographic footprint. The problem is, it took far longer than expected for the latest round of NGTL expansions to win final approval from Canadian regulators. Today, we review the next phase of the pipeline’s system development, and what the regulatory delay might mean for Western Canada’s gas market.
By the middle of the decade, LNG Canada should be sending its first cargoes of Canadian-sourced LNG to Asian markets. More importantly, Canada for the first time will have an alternative export market for its natural gas supplies — for more than 50 years, piping gas south to the U.S. has been its only option. But getting gas from the Montney and Duvernay production areas to the British Columbia coast is no easy task. It requires the construction of an entirely new, 2.1-Bcf/d pipeline — expandable to 5 Bcf/d — much of it over very rugged terrain. Coastal GasLink, as the planned pipe is known, has also faced major regulatory hurdles. Today, we conclude a two-part series with a look at where the pipeline project stands today.
When plans for LNG Canada, a big LNG export project on the British Columbia coast, were sanctioned two years ago this month, the move came as a welcome sign that Western Canadian natural gas producers might finally be able to break their long-standing reliance on just one export customer: the U.S. Access to Asian and other overseas gas markets became a high priority, in part because U.S. demand for Canadian gas had been sagging for years as production in the Marcellus/Utica and other U.S. plays came to meet the vast majority of domestic needs. But while construction on LNG Canada has steadily advanced, there are signs that delays could be mounting. Today, we begin a two-part update on this all-important Canadian LNG export project and its accompanying Coastal GasLink pipeline.
In the past three years, two major commitments were made to construct propane dehydrogenation and polypropylene plants in Alberta to take advantage of the rising bounty and generally low cost of propane supplies in Western Canada. Two Calgary-based midstream companies, Inter Pipeline Ltd. and Pembina Pipeline, each started developing PDH-PP plants in Alberta’s Industrial Heartland area northeast of Edmonton. But then came COVID-19, which set back the timeline for one of the projects and put the other on ice. All this comes as Western Canada’s propane market is in greater flux than usual, and facing a tightening supply/demand balance as exports to Asia ramp up. Today, we provide a status check on the development of these two plants, and what the increase in demand might portend for propane balances in the next few years.
Canadian gas production in 2019 turned lower for the first time in half a dozen years as very weak benchmark Canadian gas prices led to a sharp reduction in drilling and wellhead shut-ins. This year, higher prices, more drilling, and greater pipeline egress capacity were supposed to set the stage for a return of supply growth. Instead, production volumes have slipped further due to reduced drilling activity and, more recently, a spate of maintenance work. And even if there is some improvement in the next few months, annual average production looks to be on track for a second consecutive decline in 2020. But what about next year? Today, we take a closer look at the recent supply trends and whether there are any signs pointing to a production rebound in 2021.
Western Canada’s relentless, decade-long increase in crude oil production began maxing out its export pipeline capacity in the past few years. With more supply than could be carried by pipelines, exporting crude by rail tank car became the next best alternative, leading to record amounts of rail-based exports earlier this year. However, this year’s wild swings in oil prices and COVID-led demand destruction resulted in drastic production cutbacks that freed up space on pipelines and put the kibosh on more expensive crude-by-rail, at least temporarily. Things are shifting again, though. With oil production recovering somewhat in the past couple of months and excess pipeline capacity dwindling, are we headed for a resurgence in the use of rail to export Canadian crude? Today, we conclude a series on Western Canada crude production and takeaway options with an analysis of what’s ahead for crude-by-rail.
Western Canadian producers have been deeply impacted by lower crude oil prices and the demand-destroying effects of COVID-19. This past spring, oil production in the vast region dropped by an estimated 940 Mb/d, or as much as 20% from the record highs earlier this year. Taking that much production offline helped in at least one sense: it eased long-standing constraints on takeaway pipelines like Enbridge’s Canadian Mainline, TC Energy’s Keystone Pipeline, and the government of Canada’s Trans Mountain Pipeline. Production has been rebounding this summer, however, and there are indications that pipeline constraints may be returning and apportionment of uncommitted space on some pipes may again become a persistent issue. Today, we continue a review of production and takeaway capacity in Alberta and its provincial neighbors with a look at apportionment trends on the biggest pipelines.