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.
Posts from Martin King
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.
In May of this year, Western Canada’s oil production shut-ins due to weak demand and poor pricing were estimated to have peaked near 1 MMb/d, resulting in a 20% drop from the near-record production levels reached only a few months earlier. The magnitude of the production fall in such a short period of time caused a significant drop in the utilization of pipelines that transport crude oil from Alberta to other parts of Canada and the U.S. All of a sudden, pipelines that had been heavily rationing their capacity over the past couple of years to accommodate steadily rising production suddenly had ample spare capacity. With those supplies now on the road to recovery, pipelines have begun to fill some of that extra space and are moving toward rationing capacity once again. Today, we continue our review of Western Canadian production and takeaway capacity with a look at how this spring’s production cuts affected the region’s biggest pipelines.
The oil price meltdown earlier this year and demand destruction wrought by COVID-19 forced Canadian crude oil producers to throttle back output. At the height of the cutbacks in May, almost 1 MMb/d of oil supply had been curtailed due to uneconomic prices and/or lack of downstream demand. With oil prices and demand having staged a partial recovery in the past few months, production is rising off the lows and producers are talking about even higher supplies in the months ahead, with the prospect of returning to pre-pandemic levels. Today, we begin a short series that reviews the recent production pullback and discusses how producers are positioning themselves for a resurgence of their oil supplies.
Canada’s propane market has quickly morphed from one characterized by abundant supply to one facing a tightening supply/demand balance, with direct exports to Asia playing an increasingly important role. This tension became evident in May 2019, when the start-up of the Ridley Island Propane Export Terminal (RIPET) in British Columbia, Canada’s first direct export connection for propane to Asian markets, effectively eliminated the usual seasonal surplus for propane in Western Canada. With rail exports of propane to the U.S. often reliant on that excess for restocking in the summer months and as a reliable fallback supply in the cold winter months, the prospect of fewer or no periods of excess supply may be signalling trouble for some U.S. regions that have come to rely on those volumes. What’s more, within a few months, another propane export terminal in BC will be starting up, further reducing what’s left for the U.S. market. In today’s blog, we conclude our series examining the Western Canadian propane market by considering the impacts of Canada-to-Asia propane sales on U.S. propane consumers and propane prices.
The Ridley Island Propane Export Terminal — Canada’s first propane export facility — has been a game changer since it started up in May 2019. Located along the coast of British Columbia, RIPET has been shipping record amounts of propane to Asian markets in recent months, just as Western Canadian propane production has been sagging due to the twin pressures of crude oil price weakness and COVID-19-related disruptions. With production down, RIPET gradually ramping up its export capacity, a second export terminal poised to come online nearby, and Canadian demand for propane holding steady, something has to give, right? Today, we examine the changing supply/demand outlook for Western Canadian propane, and what it might mean for railed exports to the U.S.
Propane exports from AltaGas and Vopak’s Ridley Island Propane Export Terminal on the west coast of British Columbia jumped to 52 Mb/d in May, the highest since it began operations in May 2019 and exceeding the terminal’s original design capacity for the second time this year. The increased exports suggest expanded capacity at the facility and the potential for sustained higher exports from there even as Western Canada’s propane supplies plateaued in 2019 and then were hammered lower earlier this year as oil prices and demand collapsed. The resulting tighter balance in the greater Pacific Northwest region has boosted prices there, wreaking havoc on price spreads and disrupting rail movements to U.S. destinations that have relied on them for the past few years, from the Midwest to California. Moreover, Western Canadian export capacity is poised to nearly double by next spring, when a second nearby export terminal is slated to begin operations. With supply upside looking tenuous, but overseas exports set to rise further in early 2021, there is a serious squeeze emerging for propane rail exports to the U.S. Today, we consider the implications of what could be a much tighter propane market in Western Canada over the next few years.
In many parts of the world, the shift away from coal-fired to natural gas-fired generation and renewables has been gaining momentum in an attempt to curtail the output of carbon dioxide (CO2) and other greenhouse gases. The Canadian province of Alberta kicked off such an initiative in 2016 to eliminate all of its coal-fired power generation sources and replace these with either gas-fired plants, wind farms, or solar by 2030. In the past two years, the province’s major electric utilities and independent power producers (IPPs) have been accelerating these plans, such that the complete phase-out of coal will be accomplished many years in advance of the original deadline. Today, we consider this transition and highlight what should be a pivotal year for Alberta’s use of natural gas in power generation.
So far, 2020 has been another bad year for bitumen producers in Alberta’s oil sands. For the second year in a row, they have been forced to endure production curtailments, this time in response to COVID impacts on demand and the resulting record-low heavy oil prices. Still, there are at least glimmers of hope that the bitumen market will soon enter at least a modest recovery mode, and that further gains will be possible in 2021 and beyond. Moving all of that bitumen to market in pipelines and in rail cars is going to require even more diluent than the record amounts already consumed in late 2019 and early 2020. Today, we consider the outlook for bitumen production, what that outlook means for future diluent demand, and if that demand can — or cannot — be met by the various sources of diluent supply.
Producers in Alberta’s oil sands have been through good times and bad times the past few years. Sure, there’s been a lot of growth in output since 2010. But they’ve also seen wildfires that forced one-third of production offline. And pipeline takeaway constraints that sent prices tumbling and spurred government-imposed production cutbacks. And lately, they’ve been struggling through a global pandemic that slashed crude-oil demand and led to further curtailments. Despite it all, producers and the province of Alberta are hopeful about an oil sands rebound, and shippers are optimistic that they can source an increasing share of the diluent they would need to transport bitumen from Western Canada. There’s good news on that front: there appears to be plenty of diluent pipeline capacity already in place between Alberta’s diluent hubs and its oil sands production areas. Today, we continue our series by exploring the major pipeline systems that distribute diluent supply to the oil sands.