Why Waiting on Grid Batteries Will Cost Ontario More Than Acting Now

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Recently I took part in a discussion in Ottawa as part of CAFES Network’s work to raise local energy literacy, hosted by Invest Ottawa and attended by a mixed audience of residents, municipal and provincial policy observers, students, and people already working in energy and climate. Angela Keller-Herzog, founding executive director of CAFES, moderated the discussion and framed it around a simple but contested question: how fast the electricity system can change, what grid-scale batteries actually do, and whether they meaningfully improve affordability, safety, and reliability.

The three speakers were myself, speaking remotely from Vancouver, Professor Kristen Schell from Carleton University’s Department of Mechanical and Aerospace Engineering, and Devashish Paul, founder and CEO of BlueWave AI based in Ottawa. What follows are summaries of our remarks and our responses to questions from Keller-Herzog and the audience. Any errors in the summarization of Professor Schell’s and Paul’s remarks should be attributed to me, not them.

I opened by grounding the discussion in something Ontario already understands. Grid storage is not new here. The Sir Adam Beck pumped hydro facility at Niagara Falls has operated for decades, originally built to absorb excess nuclear generation at night and release it during the day. That historical example matters because it shows that the province already manages time-shifting of electricity. Grid batteries are not a conceptual leap, they are another way of doing something Ontario already does, with different constraints and advantages. Pumped hydro needs elevation and specific geography. Batteries can be placed almost anywhere, including near congestion points on the transmission and distribution network.

I focused on three claims and backed each with evidence. Batteries make electricity cheaper, safer, and healthier. The cost argument rests on asset utilization. Transmission and distribution infrastructure is built to meet peak demand, which in Ontario occurs on hot summer afternoons and evenings. The rest of the time, those wires sit partially unused, often at 30% to 60% utilization. Batteries flatten peaks and fill valleys, raising utilization closer to 70% or 80%. When expensive infrastructure is used more hours per year, the amortized cost per kWh falls. This is not theoretical. Australia’s grid-scale battery deployments delivered documented savings of about $116 million Australian in a single year by reducing peak prices, providing fast frequency response, and avoiding network upgrades.

On safety and health, I addressed concerns about battery fires directly. Batteries are increasingly replacing gas peaker plants, which are the marginal generators during peaks in Ontario. Gas plants produce chronic air pollution and associated health impacts every year they operate. I compared those impacts to the emissions from a well-publicized battery fire in California and found no measurable health impacts from the battery incident, while the displaced gas plant had ongoing public health costs. Battery design has also changed. Most grid systems now use LFP chemistries with lower thermal runaway risk, deployed in spaced containerized layouts so fires cannot propagate. The California incident occurred in an enclosed building, a configuration that is no longer standard practice.

I then placed Ontario in a global context. Five years ago, grid batteries were marginal. Last year alone, more than 100 GWh of new battery storage was deployed globally, with cumulative installed capacity exceeding 200 GWh and rapidly approaching the TWh scale. In power terms, grid batteries now exceed global pumped hydro capacity additions. This is no longer a pilot technology. It is infrastructure.

For more on my remarks, my slides and fleshed out speakers notes can be seen in this CleanTechnica article.

Professor Kristen Schell followed by laying out the physical realities of the grid in a structured way. She described electricity systems as a constant balance between supply, demand, and the wires that connect them, where imbalance produces brownouts or blackouts. Using Ontario maps and data, she showed how most large generation sits in the west of the province, especially nuclear plants like Bruce, while demand stretches eastward with limited interprovincial connections. Eastern Ontario, including Ottawa, is served by a small number of major transmission corridors that already experience congestion during peak demand.

She then compared Ontario’s summer-peaking system to Quebec’s winter-peaking system, which must meet demand approaching 40,000 MW due to electric space heating. Ontario’s current peak is closer to 24,000 MW. Her research examined what would happen if Ontario fully electrified building heating with heat pumps. During most of the year, additional demand would be modest, but during extreme cold events peak demand could reach roughly 90,000 MW, more than four times current capacity. Her conclusion was not anti-electrification, but pragmatic. Seasonal peaks driven by rare cold events require different solutions than daily peaks.

That distinction framed her assessment of batteries. Grid-scale battery energy storage systems are typically sized around 250 MW with two to eight hours of discharge duration. They are effective for daily peaks, not seasonal ones. Drawing on Australian and Californian examples, she showed how batteries charge on excess midday solar and discharge into evening peaks, reducing gas generation. Ontario has already contracted about 1.8 GW of batteries, roughly 7.5% of peak demand. Modeling by her group suggests annual system savings of about $14 million if those batteries are optimally dispatched.

She also addressed an often-missed point. Batteries do not create energy. They shift it. Poorly designed incentives could increase congestion by pulling energy across constrained lines at the wrong times. With proper market signals, batteries can instead relieve congestion and defer billion-dollar transmission upgrades. Her conclusion was measured. Batteries are among the cheapest near-term flexibility options at roughly $1,000 per kW compared to $20,000 per kW for new nuclear or SMRs, but they must be paired with new generation and thoughtful system planning.

Devashish Paul approached the same transition from a software and operational angle. He explained BlueWave AI as a company formed in the narrow window where research insights become deployable technology, before incumbents dominate. His core argument was that variable renewables make grids too complex for human operators to manage manually. Forecasting, dispatch, congestion management, and price arbitrage now require automated systems making tens of thousands of decisions per year.

He described BlueWave’s platform as a real-time control layer built on decades of historical grid data, combined with predictive models for load, wind, and solar. For batteries, he used an aviation analogy. A battery without software is like an aircraft without autopilot. It has capability but lacks precision. Human operators cannot respond optimally across 8,760 hours per year. Software can.

He extended this logic to electric vehicles. Aggregated EV batteries already represent more storage capacity than grid-scale systems in many jurisdictions. BlueWave’s EVerywhere platform allows drivers to opt into grid-aware charging while preserving their preferences for departure time and state of charge. In aggregate, this shifts load away from peaks and absorbs excess generation overnight. He quantified this at roughly 150 GWh of mobile storage per week across deployed vehicles, with about 750 MW of controllable charging power in evening hours.

Paul then introduced data centers as the next major load to manage. Many computing workloads are flexible in time and location. In the UK and India, grid operators are already coordinating data center operation with wind and solar availability, throttling compute loads when renewable generation is abundant. His argument was that software-enabled coordination can reduce the need for massive grid buildouts driven by single large customers.

The moderated discussion pushed into tradeoffs and risks. Angela Keller-Herzog asked how batteries compare to traditional infrastructure upgrades like new substations. Professor Schell replied that batteries and rooftop solar can defer some upgrades, but wires and generation still matter. Paul added that regulatory structures in Ontario limit behind-the-meter solutions, slowing cheaper alternatives. When I responded, I broadened the frame, noting that in places like Pakistan, 32 GW of mostly rooftop solar was deployed rapidly because tariffs favored panels over batteries, powering textile factories and reducing grid stress. Falling battery prices are now closing that gap everywhere.

When asked whether software and batteries can really replace gas peakers, Paul emphasized reliability concerns in cold climates. Gas peakers are dispatchable on demand, while renewables depend on forecasts that are never perfect. I responded by challenging the assumption that fossil generation is inherently reliable, pointing to the Texas freeze where gas, coal, and nuclear all failed simultaneously. Reliability comes from diversity, design and redundancy, not fuel type.

Angela then asked me directly why batteries are now competing with gas rather than complementing it. I explained that gas sets marginal electricity prices during peaks, often at $76 per MWh or higher in Ontario, and much more during extreme events. Gas plants depend on those peaks for revenue and often operate at only 25% to 30% annual utilization. As batteries flatten peaks and bid into markets with near-zero marginal cost, they undercut gas revenues. Rising gas prices driven by depletion and LNG exports accelerate this effect. Globally, this is already stranding gas assets.

On the cost of waiting, Professor Schell estimated tens to hundreds of millions of dollars in added risk and emergency costs if storage is delayed. Paul argued that waiting locks in legacy systems and blocks experimentation with distributed assets. I added that incremental deployment works. The UK built out one and two hour batteries first, then doubled energy capacity behind the same grid connections, reaching near-complete short-duration coverage by the end of this decade.

Audience questions pushed into nuclear policy, mining impacts, and predictability. On nuclear, Paul described Canada as an outlier at international forums, emphasizing nuclear and LNG while much of the Global South focuses on solar and storage. His view was that unit economics will override policy inertia over time. On mining, I answered directly, drawing on work with critical minerals experts. The total material required for an electrified system is far smaller than the ongoing extraction and combustion of fossil fuels. Metals persist for decades or centuries and are recycled. Fossil fuels are burned once. Many batteries already see second lives as stationary storage before recycling.

On predictability and reliability, Professor Schell explained that atmospheric chaos limits perfect forecasts, but long-term contracts manage financial risk. I added empirical evidence. Denmark and Germany run grids with much higher renewable penetration than Ontario and average outage durations of about 12 to 13 minutes per customer per year, compared to roughly two hours in Ontario. Variability does not equal unreliability in practice.

Across the discussion, the underlying theme was consistent. Batteries are not speculative technology. They are infrastructure. Their value depends on economics, software, and regulation as much as chemistry. The limiting factor is no longer physics or cost, but institutional willingness to adapt.