Canadian Energy Centre
Canadian renewable propane could be a fuel of the future
From the Canadian Energy Centre
‘We want to make sure we reduce emissions while keeping in mind affordability and reliability’
Four years ago, Craig Timmermans’ two Ontario radio stations became Canada’s first to go on the air from off the grid.
Faced with an $80,000 connection fee and ongoing electricity delivery costs, Timmermans opted for another solution: solar and propane.
“I did our power calculation: five staff, hot water tank, heating system, etc., right down to a coffee maker…then we need a heating source, so it made sense to go with propane,” he said.
“When I looked at all the different heating systems, I found that propane is hands down the most efficient.”
Now Timmermans is building a new home that will run exclusively on propane. He says he wanted propane appliances due to their efficiency.
Ontario radio operators KT and Craig Timmermans power their off-grid business with propane and solar. Photo supplied to the Canadian Energy Centre
“A propane cooking stove is the best cooking appliance…The heat is continuous, it’s instant. It just works so well.”
Lower environmental footprint
Propane serves many purposes in Canada, from supporting mining and oil and gas operations to fueling heating, cooling, cooking and power in remote, off-grid communities.
In these communities, propane can replace diesel with a lower environmental footprint. Propane’s carbon intensity is estimated at 72 grams of CO2 equivalent per megajoule, compared to 100 grams for diesel.
That could be slashed by more than half with a move to renewable propane, according to the Canadian Propane Association (CPA). The CPA has commissioned a new report that looks at potential pathways to producing renewable propane in Canada.
Propane storage tank. Getty Images photo
Pairing with heat pumps and hybrid energy systems
The report serves as the foundation of the CPA’s roadmap for scaling up renewable propane production in Canada.
The CPA says the fuel is ideal for pairing with electric heat pumps to provide back-up heat in low temperatures, especially in remote regions that are not near natural gas grids.
It’s also promising for hybrid systems where solar or wind provides baseload energy and renewable propane provides support when renewables are not available.
Part of propane’s appeal – renewable or otherwise – is that it’s easily liquefied and stored in pressurized cylinders, making it a versatile energy source used almost anywhere, the CPA says.
“We want to make sure we reduce emissions while keeping in mind affordability and reliability as key pillars in any energy transformation,” said CEO Shannon Watt.
“Propane goes where other fuels can’t go.”
Producing renewable propane
Today, most propane produced in Canada comes as a byproduct from natural gas processing.
Among other sources, renewable propane can be co-produced with renewable diesel and sustainable aviation fuel, made primarily from plant and vegetable oils, animal fats or used cooking oil.
Cost is the barrier to renewable propane production – about double what it takes to produce conventional propane, the CPA says.
The United States is offering incentives for renewable propane that are not available in Canada.
Through the Inflation Reduction Act, Renewable Fuel Standard and Low Carbon Fuel Standard, renewable propane producers can receive C$20 per gigajoule (or more than C$30 per GJ in California).
Through Canada’s Clean Fuel Regulations, the incentive is just over C$5 per GJ, or about C$10 per GJ in British Columbia.
“In order to attract investment the same way as the U.S. under the Inflation Reduction Act, we need to have competing measures in place,” Watt said.
“We’ve got the technology and we’ve got the feedstocks. We’ve got a lot of those big puzzle pieces that we need. Now we need the dollars to flow.”
The Ridley Island Export Terminal in Prince Rupert, B.C. ships Canadian propane to overseas markets. Photo courtesy AltaGas
Exporting renewable propane to the world
A large-scale renewable propane industry wouldn’t just benefit Canadians, she said.
That’s because global demand for propane is growing.
Market research firm IMARC Group projects world propane use will rise to nearly 250 million tonnes by 2032, more than one-third higher than demand last year.
The transition to cleaner energy sources is a major factor propelling growth, analysts said.
Until recently, Canada’s only propane exports went to the United States. That changed with the startup of two export terminals at Prince Rupert, B.C.
Since 2017, Canada’s propane exports outside the U.S. have grown substantially, reaching 42 per cent of total propane exports in 2023, according to the Canada Energy Regulator.
“We export more and more propane to non-U.S. locations,” Watt said.
“Now, roughly 50 per cent of Canadian propane is shipped to South Korea, Japan and Mexico, displacing higher emission intensity sources, namely coal and timber.”
Exporting renewable propane would take the benefits a step further, she said.
“That carries the conversation on about reducing global emissions and not just what’s happening in our own backyard.”
From the Canadian Energy Centre
By Cody Ciona
‘Alberta has never seen this level and volume of load connection requests’
Billions of investment in new data centres is still expected in Alberta despite the province’s electric system operator placing a temporary limit on new large-load grid connections, said Carson Kearl, lead data centre analyst for Enverus Intelligence Research.
Kearl cited NVIDIA CEO Jensen Huang’s estimate from earlier this year that building a one-gigawatt data centre costs between US$60 billion and US$80 billion.
That implies the Alberta Electric System Operator (AESO)’s 1.2 gigawatt temporary limit would still allow for up to C$130 billion of investment.
“It’s got the potential to be extremely impactful to the Alberta power sector and economy,” Kearl said.
Importantly, data centre operators can potentially get around the temporary limit by ‘bringing their own power’ rather than drawing electricity from the existing grid.
In Alberta’s deregulated electricity market – the only one in Canada – large energy consumers like data centres can build the power supply they need by entering project agreements directly with electricity producers.
According to the AESO, there are 30 proposed data centre projects across the province.
The total requested power load for these projects is more than 16 gigawatts, roughly four gigawatts more than Alberta’s demand record in January 2024 during a severe cold snap.
For comparison, Edmonton’s load is around 1.4 gigawatts, the AESO said.
“Alberta has never seen this level and volume of load connection requests,” CEO Aaron Engen said in a statement.
“Because connecting all large loads seeking access would impair grid reliability, we established a limit that preserves system integrity while enabling timely data centre development in Alberta.”
As data centre projects come to the province, so do jobs and other economic benefits.
“You have all of the construction staff associated; electricians, engineers, plumbers, and HVAC people for all the cooling tech that are continuously working on a multi-year time horizon. In the construction phase there’s a lot of spend, and that is just generally good for the ecosystem,” said Kearl.
Investment in local power infrastructure also has long-term job implications for maintenance and upgrades, he said.
“Alberta is a really exciting place when it comes to building data centers,” said Beacon AI CEO Josh Schertzer on a recent ARC Energy Ideas podcast.
“It has really great access to natural gas, it does have some excess grid capacity that can be used in the short term, it’s got a great workforce, and it’s very business-friendly.”
The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.
Wapisiw Lookout, reclaimed site of the oil sands industry’s first tailings pond, which started in 1967. The area was restored to a solid surface in 2010 and now functions as a 220-acre watershed. Photo courtesy Suncor Energy
From the Canadian Energy Centre
By CEC Research
Mines demonstrate significant strides through technological innovation
Tailings are a byproduct of mining operations around the world.
In Alberta’s oil sands, tailings are a fluid mixture of water, sand, silt, clay and residual bitumen generated during the extraction process.
Engineered basins or “tailings ponds” store the material and help oil sands mining projects recycle water, reducing the amount withdrawn from the Athabasca River.
In 2023, 79 per cent of the water used for oil sands mining was recycled, according to the latest data from the Alberta Energy Regulator (AER).
Decades of operations, rising production and federal regulations prohibiting the release of process-affected water have contributed to a significant accumulation of oil sands fluid tailings.
The Mining Association of Canada describes that:
“Like many other industrial processes, the oil sands mining process requires water.
However, while many other types of mines in Canada like copper, nickel, gold, iron ore and diamond mines are allowed to release water (effluent) to an aquatic environment provided that it meets stringent regulatory requirements, there are no such regulations for oil sands mines.
Instead, these mines have had to retain most of the water used in their processes, and significant amounts of accumulated precipitation, since the mines began operating.”
Despite this ongoing challenge, oil sands mining operators have made significant strides in reducing fluid tailings through technological innovation.
This is demonstrated by reductions in “legacy fluid tailings” since 2015.
Legacy Fluid Tailings vs. New Fluid Tailings
As part of implementing the Tailings Management Framework introduced in March 2015, the AER released Directive 085: Fluid Tailings Management for Oil Sands Mining Projects in July 2016.
Directive 085 introduced new criteria for the measurement and closure of “legacy fluid tailings” separate from those applied to “new fluid tailings.”
Legacy fluid tailings are defined as those deposited in storage before January 1, 2015, while new fluid tailings are those deposited in storage after January 1, 2015.
The new rules specified that new fluid tailings must be ready to reclaim ten years after the end of a mine’s life, while legacy fluid tailings must be ready to reclaim by the end of a mine’s life.
Total Oil Sands Legacy Fluid Tailings
Alberta’s oil sands mining sector decreased total legacy fluid tailings by approximately 40 per cent between 2015 and 2024, according to the latest company reporting to the AER.
Total legacy fluid tailings in 2024 were approximately 623 million cubic metres, down from about one billion cubic metres in 2015.
The reductions are led by the sector’s longest-running projects: Suncor Energy’s Base Mine (opened in 1967), Syncrude’s Mildred Lake Mine (opened in 1978), and Syncrude’s Aurora North Mine (opened in 2001). All are now operated by Suncor Energy.
The Horizon Mine, operated by Canadian Natural Resources (opened in 2009) also reports a significant reduction in legacy fluid tailings.
The Muskeg River Mine (opened in 2002) and Jackpine Mine (opened in 2010) had modest changes in legacy fluid tailings over the period. Both are now operated by Canadian Natural Resources.
Imperial Oil’s Kearl Mine (opened in 2013) and Suncor Energy’s Fort Hills Mine (opened in 2018) have no reported legacy fluid tailings.
Suncor Energy Base Mine
Between 2015 and 2024, Suncor Energy’s Base Mine reduced legacy fluid tailings by approximately 98 per cent, from 293 million cubic metres to 6 million cubic metres.
Syncrude Mildred Lake Mine
Between 2015 and 2024, Syncrude’s Mildred Lake Mine reduced legacy fluid tailings by approximately 15 per cent, from 457 million cubic metres to 389 million cubic metres.
Syncrude Aurora North Mine
Between 2015 and 2024, Syncrude’s Aurora North Mine reduced legacy fluid tailings by approximately 25 per cent, from 102 million cubic metres to 77 million cubic metres.
Canadian Natural Resources Horizon Mine
Between 2015 and 2024, Canadian Natural Resources’ Horizon Mine reduced legacy fluid tailings by approximately 36 per cent, from 66 million cubic metres to 42 million cubic metres.
Total Oil Sands Fluid Tailings
Reducing legacy fluid tailings has helped slow the overall growth of fluid tailings across the oil sands sector.
Without efforts to reduce legacy fluid tailings, the total oil sands fluid tailings footprint today would be approximately 1.6 billion cubic metres.
The current fluid tailings volume stands at approximately 1.2 billion cubic metres, up from roughly 1.1 billion in 2015.
The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.
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