Alberta natural gas storage, one of the largest regional storage hubs in North America, is experiencing one of its slowest cumulative storage injection rates in years and could be headed to a 13-year low for storage levels by the end of the current injection season. That may seem ominous for the chilly Alberta and Canadian winter heating season, not to mention gas exports to the U.S. So far, though, winter gas forward prices for the Western Canadian gas price benchmark of AECO have registered a relatively modest market response, staying in line with last winter’s average spot price. Today, we take a closer look at the market’s apparent lack of concern over low Alberta gas storage.
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The options for moving Western Canada’s natural gas supply out of the region are limited. This situation has become more acute in the past few years with the upswing in associated gas production from specific areas within the sprawling region, meaning that not all the takeaway pipelines are created equal in terms of being able to move this incremental gas supply to downstream markets. One pipeline system — TC Energy’s mammoth Nova Gas Transmission Ltd. (NGTL) network — is ideally located to help out, given that big parts of it run through the fastest-growing production areas. But it’s been running full and is increasingly constrained. Will the planned expansions to the NGTL system be enough? Today, we continue our series on the Western Canadian natural gas market with a look at TC Energy’s NGTL network, the largest and most geographically advantaged of the pipeline systems in the region.
Canadian natural gas production — over 95% of which originates in Alberta and British Columbia — has averaged about 16 Bcf/d in 2018 and 2019 year-to-date, and this past January, it topped 16.7 Bcf/d, just shy of the peaks last seen in the mid-2000s. Production has stayed strong even as prices at AECO, the gas benchmark hub, have plummeted to historical lows in the face of relentless competition from U.S. gas supplies, slower demand growth locally, and pipeline takeaway constraints. Under these conditions, producers’ future growth prospects will come down to access to local and export demand, and that means there needs to be adequate pipeline capacity to reach those destination markets. Today, we continue our analysis of existing and potential pipeline takeaway capacity and utilization out of the region, this time with a focus on the Alliance Pipeline system.
The rise in unconventional natural gas supplies in Western Canada has forced the region to again confront a dilemma that it faced in the 1990s and early 2000s: not enough export pipeline capacity to move all that gas to market. Although demand for natural gas has been growing in Alberta’s oil sands and power generation markets, it has not kept pace with provincial gas supply growth, leading to oversupply conditions and historically low gas prices. The need to export more of the gas to other parts of Canada and the U.S. is driving some pipeline expansions in the region. The question is, will they be enough? Today, we provide an update on the utilization of existing export routes, as well as the prospects (or lack thereof) for takeaway expansions, starting with Westcoast Energy Pipeline.
Growing natural gas supplies in Western Canada have been pressuring gas prices and export pipelines in the region, but there are signs that at least some of that supply-growth pressure is being offset by rising gas demand. Though the region is pegged as primarily a winter gas market — where local demand only rises when the temperature falls into the winter extremes — non-weather-related demand for natural gas has been growing in Western Canada and looks to have further upside in the years ahead. Today, we delve into Alberta and British Columbia’s gas demand trends and their potential to help balance the region’s oversupply conditions.
Once consigned to a flat or declining profile, natural gas production in Western Canada has been increasing steadily since 2012, to the extent that it has now begun to stretch the ability of the existing pipeline network to the breaking point. Most striking is that this expansion in production has been taking place in an era of declining natural gas prices and weakening basis for Western Canada’s primary natural price marker, AECO, and rising and relentless competition from U.S. gas supplies in several of Canada’s key domestic and export markets. If the pricing, pipe egress and export situation has become so dire, why are producers still drilling for and pumping out even more natural gas? Today, we address this question in the second part of our series investigating Western Canada’s natural gas supply and demand balance.
Keyera Corp. and SemCAMS Midstream, two major midstream players in Western Canada, in mid-May announced they are proceeding with the construction of their joint-venture project — a new NGL and condensate pipeline system out of the liquids-rich Montney and Duvernay plays of Alberta. The planned Key Access Pipeline System would provide the first direct competition for the transportation of NGLs and condensate out of these producing regions, currently dominated by Pembina Pipeline Co. Any and all transportation options for the movement of condensate and other NGLs out of the Montney and surrounding plays will likely be welcomed by Western Canadian natural gas producers, who are looking to capitalize on oil-sands producers’ growing demand for homegrown sources of condensate for use as diluent in bitumen transportation. Today, we provide key details about the project and how it fits into the region’s existing condensate/NGLs market.
As Western Canadian natural gas production has been recovering off lows from a few years ago and pushing higher, one of the by-products of this recovery has been steadily rising production of natural gasoline, an NGL “purity product’ also known as plant condensate. Condensate production has been growing so much that Pembina Pipeline Corp. — a leading transporter of natural gasoline in the region — has been undertaking another round of expansions to its Peace Pipeline system to move more of the product to the Alberta oil sands. There, condensate is used as a diluent to allow the transportation of viscous bitumen to far-away markets via pipelines or rail. Today, we take a closer look at Pembina’s effort to expand the Peace Pipeline.
The shutdown of natural gas production from the Sable Offshore Energy Project on Canada’s East Coast as of January 1, 2019, increased the Canadian Maritimes’ reliance on gas exports from New England this winter as consumers worked to link up with fresh supply to replace SOEP. The tightening supply in the region has prompted expansion plans from TransCanada to move more Western Canadian and Marcellus/Utica gas to New England utilizing its Mainline and other eastern systems. Today, we conclude our series examining the potential impacts of SOEP’s demise by examining new plans to bring more gas to the region.
After 19 years of natural gas production from the waters off the Canadian Maritime provinces, ExxonMobil, operator of the Sable Offshore Energy Project (SOEP), shut down production there, effective January 1, 2019. The closure further limits gas supply options for the already supply-constrained Maritimes and New England regions. Will the shutdown put even more stress on the already overtaxed gas pipeline system in New England? And will it spur increased flows of Western Canadian gas into northern New England and Canada’s Maritime provinces? Today, we continue our series examining the potential impacts of SOEP’s demise on New England gas markets.
After 19 years of natural gas production from the waters off the Canadian Maritime provinces, ExxonMobil, operator of the Sable Offshore Energy Project, shut down production there effective January 1, 2019. Though the closure had been announced well in advance, the end of SOEP output has left the two natural gas-consuming provinces in the region, New Brunswick and Nova Scotia, without any indigenous gas supplies. It’s also made them fully reliant on either pipeline gas from the U.S. Northeast and Western Canada or imported volumes of LNG into the Canaport Energy terminal in New Brunswick. Will the shutdown put even more stress on the already overtaxed gas pipeline system in New England? And will it spur increased flows of Western Canadian gas into northern New England and the Maritimes? Today, in Part 1 of this blog series, we begin an examination of the potential impacts of SOEP’s demise on New England and Eastern Canadian gas markets.