MQM Blog: SMRs in Canada – Powering Remote Mines 

Canada’s approach to small modular reactors (SMRs) has moved from white papers to real steel in the ground. It’s not just a decarbonization story—it’s about making expensive, remote operations work better. For mining, where logistics can make or break a project, SMRs offer something straightforward: reliable, round-the-clock power and high-grade heat without the endless diesel convoys.

Where things stand. Ontario Power Generation is building the first grid-scale SMR in North America at Darlington using GE Hitachi’s BWRX-300. Saskatchewan has chosen the same design as its reference. New Brunswick is advancing two advanced reactors at Point Lepreau, including ARC’s 100-MW sodium fast reactor, which cleared a key Canadian pre-licensing review milestone, and Moltex’s molten-salt concept. At the micro end, the proposed 5-MW(e) MMR demonstration at Chalk River has gone through intensive regulatory scrutiny, underscoring Canada’s insistence on a careful, stepwise approach. In short: the supply chain, the regulator, and multiple provinces are now hands-on with SMRs.

Why mining is the natural early adopter. The economics of remote power are punishing. Diesel is simple, but once you factor in winter roads, weather, storage, volatility, and maintenance, effective electricity costs can get eye-watering. Natural Resources Canada now explicitly frames SMRs for mining as a way to cut fuel exposure, stabilize energy costs, and improve environmental performance. An SMR can anchor a site microgrid—electricity, process heat, even hydrogen production for haul trucks—with renewables and batteries layered on top to trim peaks and improve flexibility. Ottawa is also seeding the ecosystem through programs focused on enabling SMRs, codes and standards, and domestic supply chains. That matters to a miner who wants proven kit and Canadian vendors, not bespoke science projects.

Social licence is moving from abstract to practical. Indigenous participation is becoming a defining feature of nuclear proposals. In New Brunswick, First Nations have signed on to explore SMR opportunities tied to industrial development at Belledune. These are early-stage agreements, but they signal a constructive, partner-first posture that other provinces—and mining proponents—can learn from. The playbook is evolving: early engagement, clear benefits, and optionality for equity participation.

Québec’s position. Hydro-Québec’s 2035 plan keeps the province focused on upgrading existing hydro facilities and building new ones along with wind, and storage. It also leaves the door open to revisit nuclear—explicitly mentioning the Gentilly-2 site for a potential new plant or SMRs after 2035—if the technology, costs, and social acceptability align. That’s a sensible stance for the main grid. But it doesn’t solve the power problem hundreds of kilometres north where major resources sit far from transmission. For those sites, the credible nuclear path is onsite or near-site generation paired with a hybrid microgrid.

What this means for Lac Otelnuk and similar projects. A large iron ore development in the Labrador Trough needs serious, steady power—for crushing and grinding, dewatering, winter heat, camp services, and potentially for making hydrogen to decarbonize trucks and rail. The traditional answer is diesel plus a patchwork of wind, some solar, and a lot of battery storage. An SMR changes the conversation:

• It replaces fuel-price volatility with a capital asset and multi-year refuelling cycles.
  
• It shrinks the logistics tail (fewer flights and winter road shipments).
  
• It scales with the mine plan: start with construction power, add modules as throughput rises, and demote diesel to backup.
  

There are two practical families to look at. First, micro-SMRs (≈5–15 MW(e)), which can be deployed in steps and married to wind/storage for an efficient hybrid. Second, 100–300 MW(e) SMRs—ARC-100 and BWRX-300 are the most advanced in Canada’s pipeline—that can anchor a mine-plus-infrastructure hub including processing and community power. The right answer depends on ore throughput, process design, and how much you want to localize downstream activities.

Regulatory reality. Canada’s regulator, the CNSC, runs a three-stage licensing process (site prep, construction, operation). Before that, many vendors complete an optional Vendor Design Review to surface issues early; several designs have cleared meaningful phases with no fundamental barriers identified. For a mining-led project, expect a rigorous, transparent process with Indigenous and public engagement baked in. The key is to pick a design that has already progressed in Canada and comes with an experienced operator—think “energy-as-a-service” so nuclear operations don’t sit on the miner’s balance sheet.

Commercial structure and partnerships. The winning model blends three pieces: a proven design with Canadian licensing traction; a qualified operator or utility partner; and an Indigenous partnership that shares long-term benefits. Layer in federal support aimed at standards, supply chain, and R&D, and the risk profile for first-of-kind deployments starts to look manageable.

Bottom line. Canada’s SMR file is now anchored by real projects, real partners, and a regulator the world respects. For Québec, the main grid will continue to lean on hydro and wind—and may eventually revisit nuclear at Gentilly. But for remote, energy-hungry mines, the case for onsite SMRs is getting stronger by the month. If projects like Lac Otelnuk want predictable, low-carbon power at scale, it’s time to evaluate nuclear-anchored microgrids alongside the usual diesel-plus-renewables stack—and to start those conversations with communities and operators early, while the supply chain is forming and the window for first movers is still open.