Ontario’s Energy Cost Landscape Is Shifting — Here’s What Ontario ICI Program Participants Need to Know

Ontario’s electricity market is entering a significant transformation we’ve haven’t seen in decades. On May 1, 2025, the Market Renewal Program (MRP) went live, introducing locational marginal pricing (LMP), a Day-Ahead Market, and Ontario Zonal Pricing (OZP), replacing the legacy HOEP. The results: the core pricing signals Ontario ICI customers rely on are fundamentally changing. At the same time, Global Adjustment costs are projected to shift dramatically through 2030 as the province navigates nuclear refurbishments, long-term capacity procurement, and rising electrification demand. For Class A and Class B participants in the Ontario ICI program, the cost management playbook needs a rewrite.

From HOEP to OZP: A New Pricing Reality

MRP went live May 1, 2025. HOEP is retired, replaced by Ontario Zonal Pricing across four zones (Northwest, Northeast, Southeast, Southwest). Approximately 970 generator and load nodes now produce locational marginal prices. The system operates with a two-settlement process: Day-Ahead Market plus Real-Time settlement. The IESO projects $700 million in savings over the first decade through optimized dispatch. The key shift: prices now vary by location AND by hour, creating both risk and opportunity for load-flexible consumers.

Under the old uniform HOEP model, a facility in Thunder Bay paid the same commodity rate as one in Toronto. Under OZP, congestion and transmission losses create meaningful price differentials — sometimes substantial. For Ontario ICI participants, this means cost management is no longer simply about “avoid the 5 peaks.” It is now about understanding your zone’s price profile every hour of every day, every day of the year.

Global Adjustment Forecasts: The Numbers Tell the Story

Total Global Adjustment spending in Ontario tells a sobering story. In 2024, system-wide GA costs stood at approximately $7.9 billion CAD. Forecasts for 2030 range widely depending on scenario: $9.4 billion under the Base case, $13.0 billion under Business As Usual (BAU), or $9.0 billion under Net Zero pathways. This spread — a potential $4 billion swing — underscores the deep uncertainty facing the market.

For Class A participants specifically, the per-megawatt obligation becomes the operative number. In 2024, Class A faced a GA rate of $347,191 per megawatt-year. By 2030, that obligation rises to $361,787/MW (Base), $518,287/MW (BAU), or $338,679/MW (Net Zero). The BAU scenario is particularly alarming: should that pathway materialize, a single megawatt of annual demand obligation could cost $518,287 — a 49% increase from today’s levels. Looking further ahead to 2033, the BAU scenario projects Class A GA rates reaching $591,590/MW.

For Class B participants, total electricity cost forecasts climb from $101.93/MWh in 2024 to $119/MWh (Base case) by 2030. Under BAU assumptions, that figure could reach $131/MWh by 2035. These costs include commodity, transmission, distribution, and GA components. 

What’s driving these escalations? Firstly, nuclear refurbishment plays a significant role. Darlington Station will undergo a major refurbishment project at an estimated cost of $12.8 billion. Pickering Station will also undergo a $26.8 billion upgrade. These costs are capitalized into the GA over their respective recovery periods, creating a structural cost floor that persists through 2030 and beyond. Long-term procurement adds further pressure: the LT1 auction awarded 2,195 MW at an average of $672/MW-BD for storage and $1,681/MW-BD for non-storage resources. LT2 is targeting another 2,000-plus megawatts by 2030. Additionally, carbon pricing — currently at $80/tonne — is legislatively scheduled to rise to $170/tonne. Each of these factors independently would create upward cost pressure. In aggregate, they represent a perfect storm of structural GA inflation.

The uncertainty itself is a critical risk dimension. A Class A customer’s GA obligation could swing by $150,000 or more per megawatt of annual demand, depending on which scenario materializes. This is not a minor variance — it is a material business risk that demands active, ongoing management.

Why Peak Shaving Alone Won’t Cut It Anymore

The traditional Ontario ICI strategy remains powerful: curtail during the 5 system coincident peaks and collect GA savings. For decades, this approach captured significant value with relatively modest operational complexity. But that playbook is becoming increasingly insufficient.

First, with Ontario Zonal Pricing now live, the commodity cost component varies both hourly and by location. A facility optimizing for only 5 annual system peaks leaves 8,755 other hours largely unmanaged. Each of those hours carries zone-specific price exposure. Second, GA costs are layered on top of increasingly volatile wholesale prices. Base case HOEP forecasts show commodity prices rising from $62/MWh in 2026 to $90/MWh by 2030. The Net Zero scenario pushes even higher, to $101/MWh.  The outcome of these wholesale swings, combined with GA inflation, creates a total cost volatility that peak-shaving alone can’t mitigate.

Third, capacity market pricing has shifted dramatically. Summer 2024 capacity auctions cleared at $332/MW. By summer 2025, that price had jumped to $645/MW, which is a 94% increase in a single year. Our takeaway is that the market is pricing in tighter supply and rising stress on the grid. For load-serving entities and large consumers with capacity obligations, these increases directly affect their bottom line. Finally, on-peak versus off-peak price spreads are widening. The difference between high-cost hours and low-cost hours has increased and creates daily arbitrage opportunities that generate substantial annual savings for facilities with flexible load. This is especially multiplied when compounded across 365 days per year

The shift is unmistakable: cost optimization has moved from a seasonal, peak-avoidance discipline to a continuous, real-time practice.

The Compounding Value of Micro-Adjustments

Under the renewed market structure, even small daily adjustments to load profiles can generate outsized annual savings. Consider this: a 2% to 3% reduction in average hourly energy costs, applied across all 8,760 hours per year, can match or exceed the savings from successfully avoiding all 5 system coincident peaks. The math strongly favors continuous optimization because the opportunity surface has expanded dramatically — from 5 critical hours per year to every hour, across every zone, every day, with both Day-Ahead and Real-Time settlement components.

For facilities with behind-the-meter storage capacity, managed EV charging infrastructure, HVAC flexibility, or process load elasticity, each of these 8,760 intervals represents an optimization opportunity. The decision framework is no longer “can we curtail during peaks?” but rather “are we capturing value in every interval?” Facilities with real-time visibility into locational pricing, demand forecasts, and their own flexible assets can make marginal load-shifting decisions that appear trivial on an hour-to-hour basis but compound to six-figure annual savings across a year.

Looking Ahead: The Case for Real-Time Optimization

Ontario’s electricity market has never been more complex — or more rewarding for participants with the right tools and visibility. The convergence of zonal pricing, rising Global Adjustment obligations, tightening supply, and expanding procurement costs has created a landscape in which real-time intelligence and automated response capability are no longer optional luxuries. They are operational necessities.

For Ontario ICI participants ready to move beyond legacy peak management into the era of data-driven optimization, the opportunity to significantly reduce all-in electricity costs is now. Edgecom Energy’s energy management platform is purpose-built for this new reality and provides real-time visibility, automated forecasting, and demand-optimization capabilities that turn market complexity into measurable, auditable savings.