This is a bit like saying they’re very close to having a baked cake needing only to buy ingredients, mix them together, and put it in the oven for a while.

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Alberta’s regulated carbon price was $95/tonne last year while the effective market price hovered around $20/tonne. The regulated price could be moved to $130/tonne tomorrow but unless market structure issues are addressed, the effective market price would continue to languish. Moving that price upward is the entire issue under negotiation.

The Memorandum of Understanding Alberta and the Feds signed in November included planned investments in data centres, pipelines, and Carbon Capture and Storage (CCS) projects – none of which can advance until this carbon pricing agreement is complete. The market problem is solvable but the two governments have not been close on this topic in nearly a decade.

Undermining the market

Alberta’s United Conservative Party (UCP) first took power in 2019. It almost immediately went to work relaxing compliance rules under the province’s Technology Innovation and Emission Reduction (TIER) program.

TIER

The Alberta NDP adopted TIER to establish a carbon price for large emitters. Benchmarks were established at an industry sector level. For example, all in-situ operations would have their emissions measured and verified, and those with the lowest emissions per output would be used to set a High Performance Benchmark (HPB) emissions level. This best-in-class HPB would then be used to establish annual emission reduction targets for all operations/plants in that sector.

This made it easy for lower-emitting plants to comply and expensive for those with more emissions, which was the plan. It encouraged larger emitters to either invest in major changes at the plant or possibly shutter the emissions-heavy facility in favour of newer, cleaner operations.

Facilities that out-performed their emission reduction requirements could earn Emission Performance Credits (EPCs) which they could sell to others. Those unable to buy credits or otherwise meet the target could pay the regulated price of carbon to the province, which could use revenue to help big emitters invest in low-carbon changes.

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2019

The UCP argued that the cost burden on larger emitters was too great and that it disadvantaged Alberta businesses compared to elsewhere in Canada (half true) and in the States (true). So, it changed TIER to lower the market price of carbon while leaving the regulated rate alone.

In 2019, operations no longer had to reduce emissions a percentage below the best-in-class HPB target for their sector. They only had to reduce their emissions based on the less stringent of the HPB or their own much higher emission levels. Of course, poor emission performers defaulted to facilities-based targets, dramatically reducing their compliance obligations.

Smaller compliance obligations meant less demand for EPCs and the increased credit supply lowered the market price of carbon.

2023

Compounding the over-supply was the renewable energy boom that hit Alberta in the early-2020s. Alberta is a largely open electricity market where developers can build generation of their choosing and sell the power to the grid. It is the only electricity market like this in Canada.

Alberta allowed renewables to earn credits for any output below an HPB based on gas generation which made the economics for renewables even more favourable, and the province became Canada’s epicentre of renewable energy growth. Roughly 6 GWs (gigawatts) of new wind and solar joined the market in just a few years adding huge volumes of EPCs to the market.

The UCP attempted to rein this in by limiting the crediting and validity periods of EPCs generated. However, the sheer volume of new credits kept the market value of EPCs at about $20-$40 even while the regulated price of carbon climbed much higher.

2025

Enter Smith’s UCP government, which adopted two new rules in late-2025 that drove the market price down to just $17/tonne. These included a pathway to earn EPCs for investments in low-carbon tech, regardless of whether emissions were lowered, and the right to reactivate recently used EPCs and use them again.

The market price likely would have tumbled further if Alberta hadn’t signed the MOU with the Feds indicating that pricing may be forced up.

TIER fixes

The regulated carbon price will climb to $130/tonne by 2030. Alberta and the Feds have lots of levers to boost the market price along with it. An easy first step would be to undo Smith’s late-2025 changes. No rational operator has made investment decisions based on those rules yet (the regulations aren’t even published), so there would be very limited economic fallout.

They could also move back to a sector-based HPB and drop the facility-specific compliance option. The renewable energy-based EPC oversupply could ease the transition in the near-term.

It could be enough to make these changes and monitor the impact through 2030, as no party wants to boost the market price all the way up to $130/tonne before then. Really, the market price should never fully reach the regulated value.

Sometime in the 2030s, the renewable energy credit glut may take care of itself as Alberta has dramatically tightened approval and costing of renewable energy projects and new installations have fallen. As HPBs tighten annually, emission-free electricity credits will decline and compliance requirements in other sectors will climb creating new demand.

If these measures are forecast to be insufficient after 2030, the Feds could take more direct action. For example, the EU established a carbon pricing system in the early 2000s and soon faced a nearly catastrophic surplus of allowances. It established the Market Stability Reserve (MSR), which removed allowances from the market when the surplus exceeded a pre-determined threshold to steady carbon prices.

In Alberta, the Feds could buy EPCs at a pre-determined rate at a volume needed to stabilize the market price closer to the regulated value.

Will Alberta agree?

The Feds aren’t empty-handed in the negotiations. The Supreme Court upheld the federal government’s right to regulate emissions, which Alberta avoids only by maintaining a comparably stringent TIER. Alberta also wants federal support for its data centre dreams that would be available under the MOU with a carbon price deal.

But, Alberta has intractably resisted a meaningful market carbon price and the Feds’ attempts to regulate it, and the province is prepping for a separation referendum so may not be in a compromising mood.

Storage capable of delivering more than ten hours of continuous electricity (long-duration) is a key enabler of renewable energy but is beyond most batteries’ capabilities. Ontario is looking to purchase 800 MWs of this LDES capacity from non-battery alternatives like pumped hydro storage (PHS) and compressed air energy storage (CAES).

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This is good news for adoption of non-emitting power and it is encouraging to see Ontario diversify its storage resource mix by adding LDES to its anticipated 3.2 GW of lithium-ion batteries. The only question is timing. Ontario is a relatively small market on the international stage and may be outrunning expected cost reductions.

The science behind PHS and CAES is established but there have been relatively few projects built globally. The accelerating wind and solar boom has created a significant need for long-duration storage, which has kickstarted global development. PHS and CAES capital costs are set to fall considerably as related expertise and manufacturing capabilities ramp up. Ontario may miss out on the savings.

Renewables on Ontario’s grid

Ontario needs LDES resources on its grid. The province’s market administrator, IESO, has said that it anticipates electricity demand will increase by 75% by 2050 and, as its estimates are always understated, it’s safe to assume demand will at least double.

Under current government direction, IESO anticipates a dramatic reduction in wind and solar energy’s role on the grid by 2050 with nuclear power making up the difference, but that doesn’t have to be the case. Renewables are cheaper and create no radioactive waste - they could continue to play a major role on the grid if properly backstopped.

Wind and solar have not historically boasted strong capacity factors, i.e., the amount of electricity an asset produces in a given time compared to the amount of electricity it would produce if it was pumping out power at max capacity. This has stumped grid planners and under-pinned anti-renewables political positions.

The tech has been improving rapidly. Land-based wind built today has a capacity factor of over 35% and wind turbines built in waters off the coast boast much better numbers. Solar still lags but is improving as module trackers (which follow the sun) and two-sided panels are implemented.

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Paired with LDES, renewables’ capacity factors would surpass gas and hydro power, with zero emissions and with less environmental impact. Renewables are also immune to spikes in global gas prices and the droughts plaguing Manitoba and Quebec’s hydro reservoirs in recent years. Adding LDES could help the province shutter gas generation long before 2047 and could limit the need for expensive new nukes.

Even if nuclear does rule the day, it is prudent to have some LDES on Ontario’s grid. Ontario claims nuclear power has a 95% capacity factor but that is based on the best results of one of our reactors and is inconsistent with decades of poor performance and outages. Production is improving for traditional nuclear power but that is partly the result of refurbs. No one knows how SMRs will perform.

LDES in hot demand

PHS and CAES are established technologies with specific constraints that have made them a last-resort option for grid planners. This unfavourability has limited development of an equipment supply chain and global expertise, which has kept costs artificially high. These constraints still exist and will continue to hamper potential development but LDES is so important to a low-carbon future that the market is growing anyway.

Pumped Hydro Storage

PHS is exactly what it sounds like. A reservoir is built at a higher elevation than a large water source. When there is excess electricity on the grid, the project uses that power to pump water from the source, up a pipe, to the higher-elevation reservoir. When the grid needs power, the water is sent back down to a turbine to generate electricity.

PHS needs a significant water source, a nearby elevated feature, and a higher-elevation reservoir. These projects can significantly impact the environment and it can be expensive to compensate for geographical shortcomings. The Ford government has already invested $285 million in the early-development of one such project owned by TC Energy, despite IESO’s warnings that the project was too expensive.

Compressed Air Energy Storage

CAES is similar but with air. When there is excess power on the grid, a compressor uses the electricity to capture air and store it in underground caverns. When the grid needs power, the compressed air is released to power a turbine.

CAES needs underground caverns (which can be artificial) and a heat source. The air expands as it is released which requires something (usually gas-fired electricity) to heat it back up so the turbine doesn’t freeze. Newer plants capture the heat created when the air is being compressed and use that to reheat the air later on (A-CAES). The tech is emissions-free but still developing and more expensive.

There are just two significant CAES projects in operation globally, in Germany and Alabama. A handful of A-CAES projects have been announced in China, California and elsewhere, which will foster supply chains and reduce costs – one study estimated 15% annually. But, the world is still early in this process. Most companies indicating interest in Ontario’s procurement have never built a full-scale operating project.

Ontario

Finding the necessary natural features is difficult, and finding them near transmission is very difficult. Ontario has some underground caverns, lots of lakes, and changes in elevation, but even here, development options are limited.

Global procurements and economies of scale

A few much bigger electricity markets than Ontario have held or announced plans for “long-duration” storage procurements though most sought projects capable of delivering just eight hours of continuous power. Australia awarded 2.2 GW in contracts to one PHS and eight battery projects. Italy awarded all of its contracts to battery projects capable of providing up to 8-hours of continuous power. And, Germany is planning 2 GW in procurements for 10-hour natural gas and battery storage later this year.

The UK and New York are leaving their procurements open to any established long-duration technologies, including PHS and CAES, but their 8-hour power delivery target could see lithium-ion batteries dominate those procurements as well. Results are due out later this spring for both.

China, of course, is leaving the rest of the world in its dust with eleven 100 MW A-CAES projects started in 2024 alone, establishing a supply chain and almost single-handedly reducing the tech costs. It is reasonable to assume those markets listed above will eventually follow China into large-scale A-CAES and PHS development - they allowed for it in procurements and they’re taking other steps to foster growth - but big cost reductions may be years out.

IESO has adopted an undisclosed “Reserve price” that it will use to cap potential costs under the procurement. And, there could also be supply chain benefits to being an early adopter. For example, leading A-CAES tech developer Hydrostor is Canadian. Being early might be worth a little extra cost with complementary supply chain investments from the government.

However, Ontario is also out front globally on incorporating SMR technology, which is also not yet benefiting from economies of scale. The province has taken a lead position on these emerging technologies without a planning rationale or energy mix scenario analysis on why it is buying these particular technologies or why it’s important for Ontario to be a global early-adopter.

Canada hasn’t proposed specific regulations, instead asking broadly whether domestic content requirements should be adopted, to which components they should apply, and what should be considered “domestic.” The idea is to encourage or require renewable energy developers benefiting from the feds’ tax credits to use Canadian-made components as much as possible.

It’d be a great idea if Canada had a competitive wind turbine, solar module or battery cell supply chain. We do not. Still possibly a great idea if the economic activity stemming from the clean energy tax credits was expected to be significant enough to entice manufacturers to set up in Canada. It is not.

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Strict domestic requirements could prevent renewable energy developers from accessing the broader tax credits, making Canada a less competitive investment market. Loose domestic requirements that developers could easily satisfy would be so limited as to be useless.

Canada would be better to target specific electricity technologies where the feds can focus manufacturing loans, tax credits, and direct contributions.

Domestic content attempts south of the border

The U.S. Inflation Reduction Act of 2022 provided roughly US$370 billion in climate and energy security spending, including tax credits for solar, BESS, land-based and offshore wind projects, and new manufacturing capacity.

It also offered bonus credits for energy projects incorporating U.S.-made components. The standard wasn’t mandatory and companies could access the underlying credits regardless of where they bought their equipment.

Congress set a high bar for the optional domestic content incentive but intended it to be achievable enough that companies would alter spending decisions to buy American even when U.S.-made products were more expensive. It mostly didn’t work because it takes years of economic certainty to build new manufacturing capacity, supply chains are complex, and making things in China is very inexpensive.

It’s hard to say exactly how ineffective the domestic content incentives would have been as the current administration subsequently took an axe to the broader renewable energy tax credits, overturned major climate change standards, and blocked offshore wind development. All of which introduced significant uncertainty and cooled investment in new manufacturing.

However, aside from the U.S.’ only major solar module maker, First Solar, ramping up capacity at its manufacturing facilities, no major manufacturing investments were made prior to Trump taking office. The U.S., which is much larger than Canada and had existing manufacturing capacity, couldn’t foster significant new investment with its painstakingly crafted domestic content credits. Canada should learn from this in designing our supply chain incentives.

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Canada is too small to build multiple domestic supply chains

The U.S. dwarfs Canada in already installed renewable energy capacity and is expected to continue outpacing Canada in new development. The U.S. is similarly small compared to the EU, which is outmatched by development in China. Canada is competing for manufacturing dollars in this global landscape.

True, we’re spending. However, Canada’s clean energy tax credits were an answer to the U.S.’ tax credits to get back on par. Countries with more advanced supply chains are also investing, including China and Germany, which this month advanced €3 billion in clean energy manufacturing and materials processing funds.

If Canada adopts broad domestic content rules in the hopes of capturing parts of multiple supply chains, we will likely attract investment in none. Canada would be better to pick one or two technologies where we have a competitive regional advantage and more directly work with industry to support domestic supply chains.

For example, nuclear generation is expensive, prone to major outages, and small module reactor technology is unproven but Ontario is adding gigawatts of additional nuclear power to its grid. The U.S. has posted some big nuclear power goals but the relatively high-risk, long-term investment profile of nukes, compared to natural gas plants, makes them tricky bets for private investors. Canada could have a temporary edge.

Reactors, electronics and balance of plant purchased by governments in Ontario, Saskatchewan and New Brunswick should be constructed in Canada with support from provinces and the feds. Canada should also enrich its own uranium. Port Hope, Ontario already produces uranium hexafluoride, the feedstock for enriched uranium, from uranium mined in Saskatchewan.

Along the same lines, the U.S. is a shaky market for offshore wind. The current U.S. administration withdrew offshore wind lease areas and in December halted construction on five projects. Courts have since intervened but the uncertainty damage has been done. Problems also existed prior to 2025, as projects were regularly delayed and cancelled due to local opposition, concerns about rate hikes, and turnovers in state government leadership.

Newfoundland and Nova Scotia are set to generate significant amounts of offshore wind power for sale elsewhere in Canada or into U.S. markets. The electricity generated could also produce green hydrogen and liquid natural gas, both of which are in hot demand in Europe. Offshore wind manufacturers tend to locate facilities near major projects. Canada could grab a foothold in the North American supply chain if we act before the U.S. sorts its issues.

The same could be true of a lithium batteries. Canada has lithium mining projects in Alberta, Ontario and Quebec, with processing plants also planned that would be well positioned to meet demand from within the country and from U.S. buyers looking to diversify away from China-based supply.

There are good options for the feds to investigate and push forward in a focused way. Temporary domestic content incentives tied to a few gigawatts of wind and solar development is not going to move the needle.

His announcement was part of a broader electric vehicle speech on February 5^th. Carney provided no further details but said the strategy would be released in the coming weeks. Consultations on scope, policy, and budget measures would likely follow this year.

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Provinces are responsible for their own electricity systems but there is a lot of room for the feds to have a big impact. The federal government already offers tax credits for investments in renewable energy, carbon capture and storage, and related manufacturing. Carney has signed an MOU with Alberta to boost low-carbon power generation, and has designated Nova Scotia’s 5 GW Wind West offshore wind strategy and Ontario’s first small module reactor (SMR) as priorities with his Major Projects Office, including $2 billion in funding for the SMR.

Altogether, Canada’s 10 provinces have announced plans to increase electricity generation by at least 72% by 2050. This is likely a low forecast as not all the provinces have released long-term plans (e.g., Saskatchewan and Nova Scotia), some are notoriously understated (e.g., Ontario), and all existing plans except Manitoba’s were prepared before our economic “rupture” with the U.S.

Given provincial plans and existing federal support, electricity generation growth is likely in-hand. Carney’s electricity strategy should also provide much needed support for transmission and electricity system materials. There are opportunities enough for the next 15 years with potential economic gains for decades.

Transmission – intra-provincial

Carney’s government has referred all three phases of British Columbia’s North Coast Transmission Line to the Major Projects Office for fast-tracking. B.C.’s new 500-kilovolt line will follow the path of existing transmission, west from Prince George to Terrace, then north to anticipated industrial and mining demand near Bob Quinn Lake. The project would also upgrade existing lines to carry additional power.

The feds should do the same in other provinces. Ontario recently advanced the first phase of what could be a major northern transmission line and roads project up to a key mining region in its northeast. The approved Greenstone Transmission Line doesn’t likely need fed intervention but the next project phases are much riskier and would benefit from federal support.

Similarly, SaskPower is undertaking reinforcement work on transmission lines southeast of Regina to connect with electricity markets in the U.S. It does not appear to have plans for needed upgrades to lines in its southwest that would unlock wind energy potential and enable future interties with Alberta. The federal government could help limit the impact to Saskatchewan ratepayers of these upgrades.

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Transmission – inter-provincial

In its MOU with Alberta, the federal government listed “construction of large transmission interties with British Columbia and Saskatchewan” as one of four projects covered by the tentative agreement. This is an area where federal involvement and financing could see significant returns.

Expansion of existing interties between B.C., Alberta, Saskatchewan and Manitoba would provide much needed resilience in the region, especially if paired with nuclear and renewable energy and long-duration energy storage.

The same would be true of boosting existing inter-tie capacity between Newfoundland & Labrador, Nova Scotia, and New Brunswick. NL and Nova Scotia’s significant offshore wind potential and NL’s hydro capacity could help resolve resource adequacy issues in the Maritimes and could provide Atlantic Canada with an alternative route to the U.S. market for sales of surplus clean electricity.

The Atlantic and Prairie provinces have too small a ratepayer base to take on the risk of major intertie transmission lines, much less shoulder the upfront costs. The lines would ultimately be moneymakers, so financing via the federal government could make sense for Canadians.

Electricity materials

Transmission support is reasonably certain to be included in Carney’s electricity strategy in some form. Less certain is support for key materials needed by Canada’s electricity grid. Carney’s Defence Strategy issued this week committed to “bring forward plans” for expanding production and processing of critical minerals but the electricity strategy could reinforce the plan.

Specifically, Alberta, Saskatchewan, Ontario and New Brunswick are all going to rely on SMRs, which require enriched uranium (up to 20%) that Canada does not produce and currently plans to procure from the U.S. It is likely in our economic and security interests to enrich domestically the high-grade uranium mined in Saskatchewan for use in Canada and for export. Building uranium enrichment facilities is an expensive undertaking and no province is likely to do so on their own.

Similarly, Canada is home to potentially significant lithium deposits, along with cobalt, fluorspar, and other minerals used in lithium-ion battery production. Federal support for minerals processing within Canada could help B.C., Manitoba, Nova Scotia and Quebec backstop their renewable energy development plans and manage peak demand, particularly in drought years with poor hydro electricity generation.

Hydro One will connect the 230 kilovolt (kV) line to the East-West Tie in Nipigon, roughly 115 kms northeast of Thunder Bay. Greenstone Transmission will then run northeast through Longlac to Aroland First Nation. It will enter operation in 2032.

Market administrator IESO recommended a shorter version of the line for construction at about $70 million in 2015. In today’s dollars, and considering the longer route and technical details, the line could cost at least $150 million. The spend is significant but the line will help meet existing needs in the area. So, it is a safe opening bet in a series of infrastructure investments aimed at providing access to a mineral rich region 300 kms north of Aroland called the Ring of Fire.

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The question is whether the Ontarians have the stomach for $2.5 billion+ in additional speculative infrastructure investments to tap into a region where there is currently just one advanced project still years away from mining production.

The opportunity

As annoying as the name is, and it is very, the Ring of Fire could provide up to 70,000 jobs and $22 billion in economic gains for Ontario, the government says. It believes the region has significant mineral deposits waiting to be pulled out of the ground and processed domestically by Canadian workers, as the country looks to onshore its supply chain in response to U.S. antics.

There are several open mining claims but only Wyloo’s Eagle’s Nest project has completed preliminary feasibility and environmental assessments. The project would mine nickel, copper, and platinum group metals, all of which are extremely valuable in today’s low-carbon and data centre-heavy economies.

Mining projects can take 15 years or more to move from exploration to production. The provincial and federal governments are working to shorten that timeline but even a wildly accelerated process would need 10 years. This buys Ontario a little time to build the necessary infrastructure for mining production if it starts right now.

The need

The area between Webequie First Nation and Attawapiskat First Nation, and south to Hearst has not been developed significantly, as compared to the regions further south or to the west. There are no all-season roads or continuous electricity infrastructure north of Aroland. First Nations communities are accessed by plane and by ice roads in the winter, though climate change has dramatically shortened the ice road season in recent years. Diesel is a common power source.

Any future mines would need all-season roads to move heavy machinery, people and ore. They would also need power to run their operations. Unfortunately, all the existing hydro power in the region is well south of the Ring of Fire and there is no transmission to carry wind, hydro, or solar power around the region.

Some have suggested that mining operations could build their own small module reactors (SMRs) or other power plants onsite, and it’s possible. Building SMRs or other electricity generation near a mine would limit the need for transmission. However, it would complicate operations and raise the cost of building new mines in northern Ontario as compared to other jurisdictions, to which mining companies would likely turn.

And there is interest in Ontario the government is hoping to foster. The map below is of active agreements with First Nations in the region, a first step in exploration and subsequent development. Few companies have strayed far from existing infrastructure but the possibilities are drawing early interest into the Ring of Fire and neighbouring areas.

The plan

The government aims to pre-build the infrastructure needed to convert that early interest into productive mines. Greenstone Transmission is the first step in this plan. Hydro One will build the line along existing highways. Simple enough.

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The next steps are more expensive and complex but could move quickly if the province decides to go all-in on its vision. This includes 550 kms over four roadwork projects:

• Upgrade of the Anaconda and Painter Lake logging roads north of Aroland,

• A new 230 km road to the Martens Falls First Nation,

• A new 200 km Northern Link to the Ring of Fire, and

• A new 120 km supply road to the Webequie First Nation.

The province has not disclosed anticipated costs but early plans estimated a $2 billion price tag. A 2019 study by research board Northern Policy evaluated recent roads projects in Ontario’s north that could indicate a smaller spend, though they didn’t evaluate roads anywhere near as extensive as these projects.

The roads projects are headed by the First Nations on whose lands they would be built and consultation with other impacted Nations is ongoing. All four projects have final environmental assessments out for public comment or about to be released, and could reach final decisions in the near-future.

Assuming the roads projects move to construction, they could provide an easy route for the remaining transmission needed to connect Aroland and Webequie. IESO has not yet studied such a line, other than to note in 2015 that mining companies could pay for the line if they wanted one. However, such studies could easily be undertaken in the next few years alongside the roadwork.

The distance would be 100 kms longer than East-West Tie but, presumably, a single circuit, so could be comparable to its $777 million cost in 2024. All in, the roads and transmission projects could cost about $3 billion or more over 10 years to open potentially many times that amount in mining opportunities and to connect First Nations increasingly isolated by diminishing ice roads.

Transmission in the area could also enable wind and solar energy projects to contribute to the region’s power grid, further mining, and other economic opportunities. These could provide additional independent revenue sources for the First Nations living there.

The challenge

Canada does not generally take a “if you build it, they will come” economic approach, with the notable exception of the Canadian Pacific Railway. British Columbia has committed to reinforcing an existing major transmission line based on its expectation of future mining and data centres but that’s uncommon and not wildly popular.

Canada is not a high-risk, high-reward kind of country. We’re careful and conservative, and it’s mostly served us well. However, as Prime Minister Carney said in Davos, “Canadians know that our old, comfortable assumption that our geography and alliance memberships automatically conferred prosperity and security is no longer valid.”

The metals and critical mineral resource is likely significant in the Ring of Fire and relatively undeveloped area to the east, there is considerable interest from mining companies in light of soaring market prices, and the First Nations in the region appear to be eager to make economic use of their land, subject to careful planning and consideration.

But, there is still only one advanced mining project in the Ring of Fire and no investment guarantee. Beyond the Greenstone Transmission Line, there are no safe bets.

Quebec might not find an overly sympathetic partner in NL, which is not generally as keen on the proposed agreement. A key member of NL’s three-person panel reviewing the deal, Michael Wilson, has called it “an outright betrayal of the people of this province and all future generations.”

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Most inter-provincial electricity deals barely muster the interest of the staff drafting the agreements, much less of the general population, but the Churchill Falls power agreement between Quebec and NL has a deep and bitter history. A history NL is wary of repeating.

The original Churchill Falls agreement was signed in 1969, when NL was a small, relatively new Canadian province with few options to make use of its massive hydroelectric potential or to raise the money needed to build the projects. Backed into this corner, it agreed to sell Hydro-Quebec 90% of the power produced at the massive Churchill Falls hydro station at the rock bottom price of $2.20/MWh for 72 years.

It was a great deal for Quebec as $2/MWh was cheaper than any alternative source of electricity in 1969. Over the next 55 years, the price became absurdly cheap compared to market prices. Hydro-Quebec said in its update on the first nine months of 2025 that it had exported power for an average $150/MWh. It earned $2.9 billion on exports in 2022 alone when wholesale electricity rates spiked.

NL saw none of that increased revenue and continued to receive its $2/MWh. Hydro-Quebec also took at 34.2% stake in Churchill Falls under the original deal, further limiting NL’s gains. Newfoundlanders have watched their neighbours rake in the revenue on the back of nearly free NL hydropower.

Hydro-Quebec allies have argued the deal was positive for NL as it made money it wouldn’t have otherwise made. It’s also true that Hydro-Quebec had all the power in the 1969 negotiation and made the most of it.

That’s how it goes in the big leagues. But, ultimately, it was a terrible deal for Newfoundlanders.

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This brings us to today. The original deal doesn’t expire until 2041 but development timelines for hydropower are 10-15 years and can be longer for nuclear, which would be Hydro-Quebec’s best options for replacing Churchill Falls. It is under pressure to get this done or to prepare to build in Quebec.

The new deal was tentatively structured in December 2024 under an MOU supported by Quebec and NL premiers no longer in power. It would see Hydro-Quebec continue to purchase 90% of power from the existing Churchill Falls project and 1,600 MWs in upgrades and expansions. It would also see Hydro-Quebec purchase nearly all of the power produced at a new 2,250 MW hydro project at Gull Island, in which it would take a 40% stake.

In short, Hydro-Quebec would continue to own 34% of Churchill Falls and a 40% stake in Gull Island. It would sell itself nearly all of the power from both projects at a pre-determined rate for 50 years. Sound familiar?

The MOU suggests no price escalators or milestones that would trigger rate increases or reviews. It seemingly includes no mechanism to enable NL to benefit from anticipated market rate increases due to AI data centres, electrification initiatives, and new industrial and mining projects, among other upward pressures.

So, why would NL sign this deal after decades of economic heartache?

The biggest change proponents highlight is the average rate increase from $2/MWh to $59/MWh. This is many times higher, so it must be good, is the argument. Some, including Wilson, have argued the accounting is faulty and that the average rate under the deal would be much less.

Assuming Hydro-Quebec is absolutely correct in its calculation of the average rate, this deal would offer NL an average rate that:

• is roughly a third of what Hydro-Quebec earned on its own wholesale deals last year,

• Hydro-Quebec described as “half the price of the renewable alternatives available to Quebec,”

• is the same as the global average levelized cost of new hydro ($57/MWh) in 2024, meaning NL would be selling the power at 2024 cost over 50 years, and

• includes no mechanism to alter the rate upward when market prices or operational costs climb.

If this deal isn’t a repeat of 1969 it has a fairly distinct rhyme. The MOU doesn’t include an automatic renewal, which is positive. However, earlier stages of the 1969 deal’s negotiation hadn’t included one either.

NL’s panel, formed by Premier Wakeham in December 2025, is reviewing the proposed deal and collecting feedback from the public until March 1. Crown corporation NL Hydro will presumably continue negotiations with Hydro-Quebec based on the panel’s findings.

Quebec’s current government is hoping to close the deal as soon as possible as it is heading for a provincial election by October and is not currently positioned to win. The Parti Quebecois is leading in the polls and has called the proposed MOU an embarrassment, though it’s unclear what it would prefer to buying massive amounts of power at cost for 50 years.

Hydro-Quebec is still a power giant, holding export relationships, favourable capital cost options, and largely controlling NL’s physical access to Ontario and the U.S. markets. At the same time, NL has completed the Maritime Link power connection to Nova Scotia, New Brunswick and Maine, it has its own mining and other industrial sectors to power, and it doesn’t need the power as badly as Hydro-Quebec to meet existing commitments.

The provinces intended that a final deal, built on the MOU, would be signed by April 1^st of this year but the timeline seems unlikely now. All eyes are on NL’s review panel to gauge how challenging a deal this will be to complete.

The Appalaches-Maine line is set to deliver 10 terawatt hours (TWhs) of clean Quebec electricity per year for 20 years. Boston will get 9.45 TWhs with the last bit going to Maine. Hydro-Quebec also signed a long-term 10.4 TWh/year deal to supply power to New York City via a separate transmission line. Deliveries to New York are slated to start later this year when the line is complete.

Historically, these export deals would be all upside for the province. From 2018-2022, Hydro-Quebec exported more than 32 TWh of electricity annually. The province produced inexpensive power from large hydro resources and sold electricity to its neighbours at higher rates, earning $2.9 billion in 2022 revenue alone. In this context, signing 20 TWh/yr in supply deals with New York City and Boston was a no-brainer.

However, the picture has changed since 2022.

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The dry years

Consecutive dry years have resulted in lower water levels and decreased hydro power production. Hydro-Quebec exported just 23 TWhs in 2023, 15.1 TWhs in 2024 and only 8 TWhs in the first nine months of 2025 (compared to 11 TWhs over the same period in 2024).

The export decline was not because its neighbours lost interest in power purchases. Ontario is managing potential shortages while its nuclear fleet is refurbished. New York’s wholesale rates were higher in 2024 than they were in 2018-2021, indicating that low-cost, clean electricity was still very much in demand there. Quebec would have benefited financially from increased exports in 2023 onward but didn’t have more to sell.

Since 2023, Quebec has been a net importer of electricity. HEC Montreal, which publishes an annual report on the province’s energy sector, said that Hydro-Quebec imported 36 TWhs in 2023. In that year, it sold just 23 TWhs to its neighbours (see below). So, some of that imported supply was to meet its own needs.

The gap between imports and exports widened in 2024, according to Hydro-Quebec’s annual report. And, it said in its November update that it had been a net importer again in 2025.

Further indications that Quebec might have overextended itself with these new deals is that, despite buying more power than it’s selling, Hydro-Quebec’s reserves have declined steadily since 2023.

Shrinking security net

Quebec’s hydro reservoirs provide insurance in meeting its own citizen’s needs and complying with supply deals. In 2021, the reserve had been as high as 154.9 TWhs, which was not far off it being able to meet the province’s entire electricity needs for a year. Impressive – most markets don’t have that luxury.

However, the reserve has been diminishing since then and was forecasted to start 2026 at just 86.9 TWhs. The level would be the lowest since 2004 and only about half of Quebec’s domestic requirements: still representing a comforting multi-year buffer against blackouts but potentially a red flag for future export deals.

It’s a tricky time to kick-off two new 10 TWh export deals. Quebec, which has said it will adhere to its export commitments, has started to make changes to provide itself some breathing room.

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Adjusting to reality

The province appears to be betting that slowing things down until 2035 is all it needs to get back on track.

Last week, the province pushed back its commitment to reduce emissions 37.5% below 1990 levels to 2035, instead of 2030, citing economic challenges and its neighbours’ poor performance in this area. This could allow the province to slow its electrification efforts, via which it intends to reduce transportation and building emissions. By slowing electrification, it could ease domestic strain on its power reserves in the next few years.

Hydro-Quebec also approved the proposed conversion of a 350 MW plant to use Renewable Natural Gas (also called biogas) to provide electricity during periods of peak demand beginning in 2029. And, it plans to launch a call for wind power proposals this spring for projects smaller than 350 MWs that could provide power by 2035.

Quebec signed an MOU with Newfoundland & Labrador in 2024 under which it could have long-term access to nearly 4 GWs of new hydropower (less Labrador’s needs) at affordable rates. The final deal is expected in April. It is possible the power available to Quebec under the final agreement will be considerably less than 4 GWs but whatever the province secures should provide a significant boost to reserves when the hydropower projects come online after 2035.

The province has reason to hope that the dry spell will end. Quebec has seen low-precipitation years come and go (see below - red are the dry years). Shortage concerns could disappear after a few years of decent water levels, like in the 2010s. The risk here is the unpredictability of climate change, which could just as easily prolong the dry spell beyond what Hydro-Quebec has faced since the 1980s and 90s.

Either way, Quebec’s plan of being the powerhouse of North America has been proven a risky bet if the province isn’t careful about overextending itself. Electrification does not mix well with multiple dry years in a hydropower dependent market. And, Quebec still has to factor in anticipated AI data centre and mining power demands – a topic it has been cautiously dodging.

Neighbouring jurisdictions would do well to take note and not assume they’ll be able to rely on imports from the clean energy giant beyond what it has already committed.

Canada must now examine all the ways in which we are intertwined with the U.S. to determine where we can remain integrated and where we need to split. Canada’s nuclear pathway should be a priority in this reconsideration.

Canada has been able to avoid hard questions about national security when it comes to our nuclear power fleet because all our operating plants use the CANDU reactor. The heavy-water reactor uses uranium dioxide, which does not require enrichment and which we make in Canada. The technology is old but could potentially be updated for new large nuclear reactors.

Problem solved, right?

Nope. Ontario, Alberta and other provinces are interested in small module reactors (SMRs). Alberta hopes they will power its $100 billion AI industry dream. Saskatchewan is hoping to finally shutter its coal-fired power. And, Ontario recently approved $7.7 billion to build a single 300 MW SMR, which it imagines will foster a nuclear tech sector in the province.

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SMRs are light-water reactors that consume enriched uranium, which we do not produce domestically and which the provinces plan to source from the U.S.

Canada has two choices if nuclear is to be part of our energy future without eroding national security:

1. Forget SMRs and focus resources on updating the CANDU reactor technology.

2. Allow SMRs into the mix but establish domestic enrichment facilities capable of producing the low-enriched uranium (up to 5%) and/or high-assay low-enriched uranium (up to 20%) needed to fuel them.

Any other nuclear pathway could leave Canada additionally vulnerable to foreign coercion as provinces would rely increasingly on imported enriched uranium to meet electricity needs.

Uranium in demand

The threats and actions the U.S. has levelled against Canada in the past year were for ridiculous, made-up reasons. Additional American control over Canada’s energy supply could further enable such inexplicable behaviour even without increasing pressure in the nuclear sector.

However, heated competition for uranium resources is likely on the horizon. Nuclear power is set to play an increasing role in powering the AI market, an area of intense global competition. The OECD’s Nuclear Energy Agency expects that nuclear energy demand could triple by 2050.

The NEA expects demand to outpace mining production by 2040, even assuming all existing, idled, planned and prospective projects and all inferred resources are mined. This is a big supply assumption that would require significant investment.

NEA expects a shortage if mines are operating at 100% (the light below colour) though they’re more likely to operate closer to 85% (dark blue). Some of this gap could be made up by secondary supply but countries will be competing for limited resources, which could also mean higher prices.

Canadian uranium miner and processor Cameco tracks uranium prices and shows them climbing back toward historic highs in 2025. Recent prices increases occurred despite sufficient global supply.

Canada’s options

Canada knows what the uranium market has in store for the world and, thanks to the past year, is painfully aware of the limits of its power. In this context, it is time to reconsider the nuclear pathway.

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If Canada were to select Option #1 above and focus on the CANDU technology, the path could be straightforward. Canada is one of the world’s largest uranium producers. The country could easily convert domestically mined ore to the uranium dioxide CANDU reactors require for the foreseeable future.

Should Canada select Option #2 and decide to invest in SMRs, it should consider establishing enrichment capabilities, rapidly. There are different methods of enriching uranium and discussions needed on where to locate these facilities but we can cover those in a future Powering Canada post.

There are two challenges often raised when Canadians consider onshoring uranium enrichment that must be addressed first: are we allowed to do it and can we afford it?

Are we allowed?

Yes, of course. Canada hasn’t enriched uranium in the past for a few reasons, including Canadians’ preference that dirty refining work be done elsewhere. It keeps the country cleaner but poorer. Processing ore is a source of untapped wealth Canada may want to onshore even if we decide to scrap nuclear power entirely.

Canada also declined to enrich uranium because the U.S. asked us/told us not to do it. Not sure that’s a good reason anymore, if it ever was one.

Under the Treaty on Non-Proliferation of Nuclear Weapons Canada signed, countries are permitted to enrich up to 20% for power plants as long as they comply with the rules of the treaty, e.g., regarding inspections, tracking, proper processing of byproducts. Canada could easily modify regulatory frameworks in the EU to ease this compliance process.

Can we afford it?

It would cost billions to build the capacity but apparently provinces are fine with big price tags. Ontario approved the first part of a $21 billion investment in SMRs in December, and more announcements are likely to follow across the country. If investing additional billions to secure Canada’s energy supply isn’t enough reason, onshoring a uranium product likely to be in high demand globally could help it make economic sense.

And, Canada may not have to foot the bill alone. The NEA anticipates significant increases in demand in several regions of the world (see below), many of which include Canadian allies who may be persuaded to invest in exchange for priority access to enriched uranium. China and/or the U.S. may be interested in such deals, too.

No matter what Canada decides on this issue, it should be a topic for reconsideration and informed debate. Governments can’t afford to casually hand over another means of foreign coercion in this post-rupture world.

PJM, America’s largest electricity market, generates more electricity than all of Canada’s grids combined and has gigawatts of new power generation waiting to supply its system. Its size and experience did not protect it. PJM has spent over $47 billion filling capacity gaps created by new data centre demand and expects to be gigawatts short of meeting its needs in 2027. Translation: AI data centres have caused electricity rates to spike and ratepayers could still face blackouts.

Nevertheless, Alberta is betting big that its future lies at the heart of Canada’s AI sector, if it can just get the rules right. It is moving fast, temporarily capping data centre connections, passing new taxes, and making progress on policies and technical rules. All while Canada’s other big grids – Quebec, Ontario, and British Columbia – have taken only early steps to prepare for the onslaught.

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It may be that other provinces aren’t as keen on AI data centres, which are insatiable power consumers. A ChatGPT query requires 10 times the power of a google search and electricity needs are expected to increase. The data centres typically consume a lot of water for cooling their servers, employ very few people, and have been non-committal on data sovereignty, i.e., keeping Canadian data in Canada.

Some provinces are cautiously considering these questions but Alberta is all in.

Attacking near-term barriers

Alberta’s biggest challenge in locking down AI data centre investment may be that its grid is dirty. Alberta has no hydro or nuclear power today. The province said it plans to build nuclear but that will take 15+ years to site, permit, and build. So, its $100 billion AI dream will need to rely on gas for the foreseeable future. This is a problem for two reasons:

1. Canada’s federal Clean Electricity Regulation (CER) will impose strict limits on electricity generation emissions in 2035. This would make powering AI data centres extremely difficult in Alberta as carbon capture and storage (CCS) at natural gas plants is prohibitively expensive. (Experienced generator Capital Power cancelled a $2.4 billion CCS project in 2024 for this reason.)

2. Young people use AI and young people like the idea of breathing outside for their entire lives. So, AI companies tend to prefer emission-free power sources.

Addressing Issue #1

Alberta is banking so heavily on AI for its economic future that it spent half of its considerable political capital with the Federal Government last year clearing this roadblock. Alberta signed a partnership MOU with the Feds in which AI was the major focus, only sharing the spotlight with oil pipelines.

Under the MOU, the Feds exempted Alberta from the CER insofar as Alberta adopts a $130/tonne effective carbon price. For context, Canada’s government had previously found that a $170/tonne carbon price wouldn’t be enough to incentivize investment in cleaner energy sources. And, the way Alberta’s carbon pricing program (TIER) works, the real carbon price will likely be much lower.

The Feds effectively absolved the province of meaningful electricity emissions accountability under the MOU. Alberta solved its CER problem.

Addressing Issue #2

The province must make itself so attractive to AI companies that they’re willing to take a chance on their young users’ interest in emissions. On this point, Alberta is working hard to speak the universal love language of business – certainty.

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Alberta shooting its shot

The province is nearing publication of final technical rules for grid connection. Data centres are weird loads and their unique power consumption behaviour can cause major reliability issues even where there is enough power. These new rules will establish predictable standards for AI companies.

Alberta’s market operator (AESO) is also developing processes this year for forecasting demand, allocating grid access, and determining transmission costs and daily rates. The new regulations would provide investment certainty for AI companies and would flesh out legislation passed in December.

One such piece of legislation provided fast-track approvals for AI data centres that bring their own power. In other words, if an AI company wants to build a data centre in Alberta, they would find a power producer to build a new generation plant and buy its power. These projects would get priority approvals and grid connections, possibly with additional benefits if they provide excess power to the grid.

If that carrot doesn’t work, Alberta also passed a stick. Data centres planning to connect to the grid will pay a new levy based on the value and age of their computer equipment and their power demands. Data centres that rely exclusively on their own generation will pay a smaller tax.

Maintaining public support

Alberta is not afraid to grind the wheels of progress to an absolute halt to keep voters on board when it needs time to think. It once paused renewable energy development for months and has now prohibited new AI data center connections until 2028.

It allowed two of the most advanced projects to squeeze in before the pause, including a Pembina Pipeline and Keneticor partnership, which purchased 970 MWs to power an unnamed customer while they build it a new gas plant. Gas generator TransAlta acquired the remaining 230 MW for a customer it had not signed as of May.

The remaining 20 GW of known data centre demand will wait to compete for grid access under the new rules. This pause could help protect ratepayers from a PJM-like mess and keep voters on board with Alberta’s push for national AI dominance.

Competition nipping at Alberta’s heels

Premier Smith directed Alberta’s Utilities Minister in October to develop a nuclear roadmap and regulatory framework to advance projects “as soon as possible” which could help cement Alberta’s lead position on AI. Provinces with cleaner grids could sneak in before then but they don’t appear to be in any kind of hurry.

Ontario and Quebec are currently home to most traditional data centres in Canada. The provinces boast large, clean grids and bountiful water resources. Both have passed legislation requiring economic benefit reviews under parameters that would affect all AI data centres. However, neither has taken steps toward adopting rules to enable development, so it is unclear how committed they are to the AI boom.

British Columbia may pass on the whole thing. It capped electricity allocations for new data centres and said it is only interested in power consumers that serve the BC economy. It hasn’t proposed an economic benefit test but its earlier actions may be informative. The province passed legislation permanently banning new connections for cryptocurrency mining, citing “its disproportionate energy consumption and limited economic benefit.” It may be that AI data centres will share the same fate on Canada’s west coast.

These developments will impact the type of power sources on our grid, whether Canada can meet our growing power needs, and the prices we pay in the years to come.

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How we deal with AI data centres

Canada is pushing to expand our economy quickly in response to US threats. Provinces must find a way to connect beneficial “major loads” to the grid without creating blackouts and rate hikes. “Major loads” are most popularly AI data centres but include refineries, LNG plants, and mining operations.

On one hand, Canada wants to make the most of the AI boom and reduce our reliance on the US for natural resource processing, which would favour connection of any and all loads looking to set up shop here. On the other hand, not all loads are created equal in long-term economic benefits.

A key power market in the US has provided a warning against a “take all comers” approach. PJM, which serves 13 eastern states, has so far accepted all major load connection requests. It has seen many billions of dollars in increased capacity spending for the near-term, is facing shortage risks, and is coping with significant uncertainty in its longer-term planning as some data centres may never be built at all.

BC, Alberta, Quebec, and Ontario have all taken early steps to manage this risk. Or rather, to buy themselves time to figure out how to manage this risk. British Columbia passed a ban on some activity and strict limitations on others. Fellow hydro producers, Ontario and Quebec built new reviews into connection processes. And, Alberta capped major load connections until 2028. Its cap was fully subscribed almost immediately.

Governments must find ways protect the grid without missing out on real economic wins. We should start to see proposals this year.

How much dirtier our power gets

Power sector emissions are set to climb in some regions over the next several years and won’t be reduced as quickly as they could be in others. The question is how dirty the grid will get.

Saskatchewan said it will spend $900 million refurbing three aging coal plants to operate them beyond the federally required shutdown date in 2030 – a date no other province is planning to exceed. Don’t shame the prairies though, Ontario is also anticipating emissions increases. Ontario has abundant clean resources but anticipates gas will play a larger role in meeting demand over the next 20 years while it refurbs and builds its many, many planned nukes.

Meanwhile in Atlantic Canada, New Brunswick is building new gas and hydro giant Newfoundland is building new diesel-fired turbines to replace older fossil fuel-fired plants.

All of these investments could have been directed to cleaner options within the current timelines and within budgetary constraints. This year could be pivotal in determining how emission-free technologies are factored into planning.

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How we overcome our fear of wires

Canadians like to fawn over Texas’ renewable sector but how did it get there? It kickstarted investment by creating competitive renewable energy zones and spending billions on transmission to advance wind power development. It worked so well that now Texas lawmakers can’t stop the renewables growth they started.

More recently, power supply development elsewhere in the US has been stymied by transmission deployment and interconnection delays. Has Canada been learning from these experiences? Nope, not really.

Canadian provinces seem oddly uncomfortable investing in new transmission, whether inter-provincial links or development-fostering lines like Texas once built. There are a few exceptions but for the most part, new transmission has been a last resort. I say it’s odd because new transmission and/or non-wire grid alternatives can reduce the new supply needed, which can save a lot of money when done properly.

Some provinces seem to be tentatively broaching the subject. BC has proposed a $6 billion+ transmission line to move power from its central east to the northwest, based on forecasted but yet to materialize demand. Alberta is reevaluating how transmission is planned and costed to improve network efficiency. And, Nova Scotia has made progress on two interprovincial links.

It remains to be seen whether any of these plans or others on the horizon will be sufficient and/or appropriate to support growth but they could indicate that Canada is getting more adventurous with transmission potential. There may be lots to talk about this year.

How well we’re able to plan ahead

Ontario has a long-term planning problem. Every annual demand forecast it has put out in the past six years has been wrong. Each year we learn that it has, once again, dramatically underestimated the province’s long-term demand in its preceding outlook.

This is largely because of how Ontario’s electricity market administrator, IESO, creates its forecast. IESO bases its forecast on near-certain known demand and performs no meaningful scenario analysis. Scenarios typically include a slow development option where there isn’t much growth, a medium estimate and a high growth alternative. They enable identification of “no regrets” investments that will be beneficial under all scenarios and help to gauge the risk in larger investments. Most major electricity markets use this tool for planning. In Canada, most don’t, which makes planning and procurement unnecessarily opaque.

The good news for Canadian ratepayers is that 2025 saw very tentative moves in several provinces toward addressing this shortcoming.

Ontario released a plan in 2024 that would see it move toward more fulsome planning and oversight though it hasn’t made any obvious steps in that direction yet. Nova Scotia has taken early steps toward establishing a market administrator tasked with preparing an Integrated Resource Plan (IRP) – a long-term plan that would be subject to review and approval. And, Manitoba is working on its second ever IRP to include long-term forecasts and alternative scenarios (see below).

This planning could be pivotal to maximizing Canada’s opportunities without overpaying. It could also help attract investment in Canada’s electricity markets via increased transparency and certainty.

How affordable we make it

Last but definitely not least in the stories to watch this year will be changes to market structure, contracts, and rates underway in multiple markets.

Almost every province has a major procurement planned this year under which they will purchase new gas, wind, solar, storage, hydro and/or nuclear power. The deal structures, the competitiveness of the processes, and the rates agreed to will impact the affordability of electricity in Canada for decades.

At the same time, Ontario, Alberta, Nova Scotia and PEI are all currently developing and/or considering major market changes. These updates impact everything from how electricity is sold, to which entities are allowed to buy and sell, to how pricing varies by location and ratepayer.

In some cases, like Ontario and Alberta, the market models are brand new. In other places, the models are well known but new to the province. What we know for sure is that utility rates have been climbing. Proposed market changes are intended to help curb or even reverse some of these increases. We will begin to understand this year the degree to which the right choices are being made.

2026 with Powering Canada

There is a lot more I haven’t touched on that will impact the shape of Canada’s electricity sector, the rates we pay, and our ability to thrive in this economic upheaval. I hope you’ll subscribe to have these updates sent to your inbox as we explore this exciting sector together this year.