At 4:23 PM on May 12, 2025, a faulty sensor at Bruce Power's Unit 6 triggered automatic shutdown. Within minutes, Ontario's wholesale electricity price hit its $2,000/MWh ceiling—the market's way of screaming that 900 MW had vanished and replacements were scrambling. For 47 minutes, industrial customers watched hourly bills exceed their typical weekly costs.
The event lasted less than an hour. The questions it raises will shape Ontario's grid for decades.
The Physics of Concentration Risk
Ontario has built one of North America's cleanest electricity systems on nuclear's back. Eighteen reactors at Bruce, Pickering, and Darlington provide 55% of provincial generation—roughly 13,000 MW of capacity that runs around the clock at marginal costs approaching zero. When everything works, it's a triumph of decarbonization without intermittency.
When it doesn't, the math turns brutal.
Bruce Unit 6's trip removed approximately 875 MW of baseload generation instantaneously. IESO's real-time market scrambled: gas combined-cycle plants ramped to maximum output within 15 minutes, imports from Michigan and New York increased by 600 MW. But the combined response fell 300 MW short for nearly an hour. During that window, every megawatt-hour cleared at the market's $2,000 offer cap—roughly 25 to 30 times typical prices.
The replacement stack tells the story. Nuclear runs at near-zero marginal cost. Gas combined-cycle plants bid $60-80/MWh. Peakers come in at $150-250/MWh. When you lose nearly a gigawatt of the cheapest generation on the system, you're buying the most expensive electrons available.
Ontario's Nuclear Dominance
Ontario's Nuclear Dominance. Source: IESO data. Eighteen reactors provide over half of Ontario's electricity—a clean energy triumph that concentrates risk.
Why Ontario's Market Design Amplifies the Signal
IESO operates differently from US RTOs, and the distinction matters. Ontario uses a two-schedule market with separate day-ahead and real-time price formation but lacks a formal capacity market. Long-term contracts provide resource adequacy; contracted resources operate at fixed prices regardless of market conditions.
This structure delivers remarkable price stability during normal operations. But contingencies reveal underlying scarcity with dramatic clarity.
Compare PJM's response to a similar event. The RTO's capacity performance construct keeps more peaking resources available and compensated. Its larger footprint—spanning 13 states—enables greater import diversity. Prices would spike, but likely not to $2,000/MWh.
NYISO's installed capacity market provides another contrast. Peaking resources bid into energy markets at costs reflecting their capacity payment recovery, moderating scarcity pricing. Ontario's generators, lacking that revenue stream, must recover investment through energy prices alone—which means contingency prices must go higher.
Neither design is objectively superior. Ontario's approach concentrates price signals; PJM's spreads them across capacity and energy payments. But Ontario's industrial customers, facing real-time exposure during a reactor trip, might prefer the American model's smoothing effect.
The Price Shock Cascade
The Price Shock Cascade. Source: IESO market data. When 875 MW of near-zero-cost nuclear vanished, Ontario bought the most expensive electrons available.
The Storage Gap
Ontario's battery storage fleet totaled 250 MW when Bruce Unit 6 tripped. Those batteries discharged fully during the price spike—and covered barely 28% of the nuclear loss.
The counterfactual is instructive. California has deployed battery storage at roughly five times Ontario's per-capita rate. At that deployment level, Ontario would have approximately 1,800 MW available—enough to cover the entire nuclear trip with margin to spare.
IESO's 2024 Resource Adequacy Framework acknowledges this gap. The procurement path targets 2,500 MW of energy storage by 2030. But current deployment lags the schedule, and reactor trips don't wait for procurement cycles.
France offers a cautionary parallel. EDF's 56 reactors provide 70% of national generation—even higher nuclear concentration than Ontario. During 2022's maintenance crisis, 32 reactors went offline simultaneously. France found itself importing power from Germany and Spain at prices exceeding its domestic market. RTE, the French grid operator, now targets 7,000 MW of battery storage by 2030. The lesson cost billions to learn.
Who Wins, Who Loses
For generators with fast-start capability, May 12 was a windfall. Resources that could reach full output within 15 minutes captured premium prices. Slower units missed the opportunity entirely—a powerful incentive signal for flexibility investment.
The Storage Gap That Cost Millions
The Storage Gap That Cost Millions. Source: IESO, California ISO data. Ontario's 250 MW battery fleet covered just 28% of the nuclear trip. At California's deployment rate, the province would have had capacity to spare.
Industrial customers with real-time price exposure learned an expensive lesson about tail risk. Fixed-price contracts and financial hedges suddenly look cheap compared to a single hour at $2,000/MWh.
For policymakers, the event reframes the storage and demand response debate. These resources seem expensive during normal operations—until you calculate their insurance value during contingencies. A 500 MW battery that prevents one hour of $2,000 pricing saves $1 million in that hour alone.
What Comes Next
Ontario Energy Board Case EB-2025-0123 now examines IESO's resource adequacy framework, with intervenors citing May 12 as evidence that current procurement understates flexibility needs. IESO counters that the event resolved without load shedding—markets performed as designed, prices signaled scarcity, resources responded.
The real debate isn't whether markets worked. It's whether $2,000/MWh volatility represents acceptable cost or system failure.
Bruce Power's license renewal proceedings continue before the Canadian Nuclear Safety Commission. The operating fleet ages. Refurbishment schedules extend into the 2030s. Each year of continued operation maintains Ontario's low-carbon supply—and carries the contingency risk May 12 illustrated.
The province's long-term energy plan calls for nuclear capacity additions, including small modular reactors. Those additions arrive after 2030. Until then, Ontario's grid depends on reactors that can trip without warning—and flexibility resources that remain underbuilt.
Forty-seven minutes of scarcity pricing is a warning shot. The question is whether Ontario builds the flexibility to prevent the next one, or waits for a longer outage to force the issue.
About the Author
Dr. Sayonsom Chanda
Dr. Sayonsom Chanda is an electrical engineer and senior scientist with more than a decade of experience in developing AI, ML, and other advanced computing solutions for the electric utility industry in US and India. He is also an energy policy thinker and a published author with more than 20 papers and 1 book.
