Canadian Energy Centre
Why Canada’s proposed oil and gas emissions cap goes against UNDRIP and the rights of Indigenous people
Indigenous Resource Network executive director John Desjarlais (centre), with Justin Bourque, president of Âsokan Generational Developments, and Shelby Kennedy, community and Indigenous relations advisor with Enbridge. Photo courtesy Indigenous Resource Network
From the Canadian Energy Centre
Q&A with John Desjarlais, executive director of the Indigenous Resource Network
The Indigenous Resource Network (IRN) is pushing back on Canada’s proposed framework to cap emissions from the oil and gas sector.
IRN executive director John Desjarlais says the proposal directly contradicts Canada’s support for the United Nations Declaration on the Rights of Indigenous People (UNDRIP).
He says the plan would cap opportunity for Indigenous communities as more take on ownership positions in major energy projects from oil and gas pipelines to liquefied natural gas terminals and carbon capture and storage projects.
Here’s what Desjarlais told CEC.
CEC: From the perspective of Indigenous communities across Canada who are involved in natural resources development, what’s your take on the federal government’s proposed oil and gas emissions cap?
John Desjarlais: There’s a lot of confidence that it will curtail production as well, and obvious concern that it’s going to mean less opportunity.
We’ve heard from communities that are saying we’re involved already in emissions reduction. There are communities that just want to advance their opportunities in that space. And it’s at a time when there’s probably the greatest appetite for Indigenous involvement, not just in ownership, but advanced business development and procurement. [It could] mean less jobs, less procurement, less ownership opportunity, less investment.
There are concerns that these impacts are not being heavily understood, measured, contemplated or considered in terms of the policy development and implementation.
CEC: How does being involved in oil and gas development benefit Indigenous communities?
JD: There’s a suite of benefits that are coming from increased engagement, and it’s much deeper than just jobs.
Communities are now jumping into revenue generating assets where they’re creating immediate cash flow, which is allowing them to start to self-determine and invest back into their community either through economic development or through infrastructure programming.
The other side to it is just the capacity that comes from being involved as an owner. Indigenous business and community leaders are being exposed to the requirements and the acumen needed to successfully participate in the ownership of decision making. That’s accelerating the development of the acumen and capacity of different indigenous communities at greater rates
CEC: How many communities would you estimate are now participating at this level?
JD: There’s probably upwards directly of at least 100 different communities now. There are double-digit communities that are involved in at least four or five different deals that are directly involved in the ownership and the benefit side, and then there’s cascading involvement of all the surrounding communities through procurement opportunities and employment. It’s growing quite quickly.
CEC: Why do you say the proposed emissions cap contradicts the United Nations Declaration on the Rights of Indigenous People?
It’s a policy that’s created to achieve certain goals. Creating those types of targets without Indigenous oversight – not just input, [but] oversight and ownership – is problematic because it contradicts the UNDRIP action plan in terms of stepping out of the way of affording Indigenous peoples and communities the ability to self-determine; to invest where they want to invest, and to grow how they want to grow.
We hear a lot of community leaders say, ‘we know what’s best for our territories.’ To have policy that limits our ability to make the decisions we want to make in regard to environmental and economic sustainability is a challenge.
CEC: What would you like to see happen?
JD: It’s a little hard to roll back and involve communities in a total redesign, but at least if we saw an understanding that there’s certainly going to be an economic impact. If there’s a production cap aspect to it, there’s going to be an economic impact to those Indigenous communities that have established livelihoods and revenue streams.
There’s the sentiment that if the government truly is advancing this in the direction that they are, then would they consider omission of Indigenous activity so they can continue advancing their economic interests and growth?
Ideally, [there would be] a policy that’s created in line with UNDRIP that works for communities, industries and governments in their goals.
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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