Energy
Federal government’s ’carbon-free’ electricity target far-fetched
From the Fraser Institute
By Elmira Aliakbari and Jock Finlayson and Tegan Hill
A recent report by the Canada West Foundation, which analyzed 25 major projects that entered the federal government’s review process between 2019 and 2023, found that all 25 were still stuck in the early stages (phase 1 or 2) of the four-phase process.
Did you know that the Trudeau government wants to “decarbonize” Canada’s electricity generation by 2035? That is, make carbon-free sources (e.g. wind, hydro and solar) the sole power source for electricity generation in Canada.
Is this possible? No.
As of 2023 (the latest year of available data), nearly 81 per cent of Canada’s electricity came from carbon-free sources. To replace the remaining 19 per cent that relies on fossil fuels over the next 10 years, Canada would need to add a massive amount of generation capacity.
Specifically, we would need approximately 23 new large hydroelectric dams similar in size to British Columbia’s Site C project. Of course, due to regulatory hurdles and approval processes, it takes a long time to plan and construct major electricity generation facilities in Canada. The Site C project took approximately 43 years (from initial feasibility and planning studies in 1971) to secure environmental certification in 2014. Construction finally began on the Peace River in northern B.C. in 2015 with completion expected in 2025—at a cost of at least $16 billion.
Alternatively, we would need more than two large scale nuclear power plants the size of Ontario’s Bruce Power, which took nearly two decades to complete with billions of dollars in cost overruns.
Or we’d need approximately 11,000 new large wind turbines, which would require clearing approximately 7,302 square kilometres of land (that’s larger than Prince Edward Island and nearly nine times larger than Calgary). The new turbines would also require substantial investments in backup power systems due to the wind’s intermittency, which of course would further drive-up costs across the electricity system.
And remember, as Canada’s population grows, electricity demand will increase significantly. The infrastructure mentioned above would only decarbonize Canada’s current electricity needs, without accounting for the additional capacity required to meet future demand.
And yet, despite its aggressive plan to decarbonize, the Trudeau government in 2019 introduced the Impact Assessment Act (IAA)—also known as Bill C-69—which added layers of uncertainty and complexity to project reviews. A recent report by the Canada West Foundation, which analyzed 25 major projects that entered the federal government’s review process between 2019 and 2023, found that all 25 were still stuck in the early stages (phase 1 or 2) of the four-phase process.
In other words, while Ottawa’s electricity decarbonization plan requires an unprecedented wave of new energy projects, the government’s own regulatory regime will make it harder for new projects to get off the ground.
The total costs of the federal government’s plan are incalculable. But we do know who will get hurt the most. Three provinces—Alberta, Saskatchewan and Nova Scotia—depend most heavily on fossil fuels to generate electricity. In Alberta, approximately 85 per cent of electricity comes from fossil fuels, mainly natural gas, while carbon-free sources generate only 15 per cent. Clearly, Alberta and these other provinces will face the greatest challenges—and heaviest burdens—in decarbonizing their grids.
In light of the basic realities of project construction timelines, regulatory hurdles and the massive financial investment required, the Trudeau government’s target to achieve 100 per cent fossil fuel-free electricity by 2035 is far-fetched. But the costs of pursuing that target will be very real and felt by all Canadians, with the size of the costs depending largely on where you live.
Authors:
This article supplied by Troy Media.
U.S. President Donald Trump’s chaotic foreign policy is unravelling years of pressure on Iran and fuelling a surge of Iranian oil into global markets. His recent pivot to allow China to buy Iranian crude, despite previously trying to crush those exports, marks a sharp shift from strategic pressure to transactional diplomacy.
This unpredictability isn’t just confusing allies—it’s transforming global oil flows. One day, Trump vetoes an Israeli plan to assassinate Iran’s supreme leader, Ayatollah Khamenei. Days later, he calls for Iran’s unconditional surrender. After announcing a ceasefire between Iran, Israel and the United States, Trump praises both sides then lashes out at them the next day.
The biggest shock came when Trump posted on Truth Social that “China can now continue to purchase Oil from Iran. Hopefully, they will be purchasing plenty from the U.S., also.” The statement reversed the “maximum pressure” campaign he reinstated in February, which aimed to drive Iran’s oil exports to zero. The campaign reimposes sanctions on Tehran, threatening penalties on any country or company buying Iranian crude,
with the goal of crippling Iran’s economy and nuclear ambitions.
This wasn’t foreign policy—it was deal-making. Trump is brokering calm in the Middle East not for strategy, but to boost American oil sales to China. And in the process, he’s giving Iran room to move.
The effects of this shift in U.S. policy are already visible in trade data. Chinese imports of Iranian crude hit record levels in June. Ship-tracking firm Vortexa reported more than 1.8 million barrels per day imported between June 1 and 20. Kpler data, covering June 1 to 27, showed a 1.46 million bpd average, nearly 500,000 more than in May.
Much of the supply came from discounted May loadings destined for China’s independent refineries—the so-called “teapots”—stocking up ahead of peak summer demand. After hostilities broke out between Iran and Israel on June 12, Iran ramped up exports even further, increasing daily crude shipments by 44 per cent within a week.
Iran is under heavy U.S. sanctions, and its oil is typically sold at a discount, especially to China, the world’s largest oil importer. These discounted barrels undercut other exporters, including U.S. allies and global producers like Canada, reducing global prices and shifting power dynamics in the energy market.
All of this happened with full knowledge of the U.S. administration. Analysts now expect Iranian crude to continue flowing freely, as long as Trump sees strategic or economic value in it—though that position could reverse without warning.
Complicating matters is progress toward a U.S.-China trade deal. Commerce Secretary Howard Lutnick told reporters that an agreement reached in May has now been finalized. China later confirmed the understanding. Trump’s oil concession may be part of that broader détente, but it comes at the cost of any consistent pressure on Iran.
Meanwhile, despite Trump’s claims of obliterating Iran’s nuclear program, early reports suggest U.S. strikes merely delayed Tehran’s capabilities by a few months. The public posture of strength contrasts with a quieter reality: Iranian oil is once again flooding global markets.
With OPEC+ also boosting output monthly, there is no shortage of crude on the horizon. In fact, oversupply may once again define the market—and Trump’s erratic diplomacy is helping drive it.
For Canadian producers, especially in Alberta, the return of cheap Iranian oil can mean downward pressure on global prices and stiffer competition in key markets. And with global energy supply increasingly shaped by impulsive political decisions, Canada’s energy sector remains vulnerable to forces far beyond its borders.
This is the new reality: unpredictability at the top is shaping the oil market more than any cartel or conflict. And for now, Iran is winning.
Toronto-based Rashid Husain Syed is a highly regarded analyst specializing in energy and politics, particularly in the Middle East. In addition to his contributions to local and international newspapers, Rashid frequently lends his expertise as a speaker at global conferences. Organizations such as the Department of Energy in Washington and the International Energy Agency in Paris have sought his insights on global energy matters.
Troy Media empowers Canadian community news outlets by providing independent, insightful analysis and commentary. Our mission is to support local media in helping Canadians stay informed and engaged by delivering reliable content that strengthens community connections and deepens understanding across the country.
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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