Ontario’s Renewed Market: One Year in Review

Ontario’s Renewed Market: One Year in Review

In the months since MRP’s one-year anniversary, Workbench Energy has analyzed the full year of market data to understand the impacts of the Renewed Market.

On May 1, 2025, Ontario’s IESO launched the Renewed Market, designed through a years-long Market Renewal Program (MRP), replacing the electricity market design that had been in place since 2002. The legacy market, built around the Hourly Ontario Energy Price (HOEP), set a single province-wide price for electricity that did not reflect where on the grid power was scarce or abundant.

MRP replaced that design with one built around nodal pricing, where each location on the grid carries its own price reflecting local supply and demand conditions, a financially binding Day-Ahead Market (DAM), and dispatch decisions that are reflected in published prices. This article takes a look at year one of MRP: what changes were made and what key patterns emerged during its first year.

What MRP Changed

From Two Schedules to One

Pre-MRP, resources were dispatched and priced through two separate schedules. One schedule calculated a system-wide market price, ignoring transmission congestion. A second schedule managed actual dispatch, accounting for those physical constraints. When the two diverged, the IESO compensated generators through Congestion Management Settlement Credits (CMSCs), out-of-market payments that were not transparent to the market. Those payments have totalled over $1.6 billion¹ since the market opened in 2002.

MRP replaced this with a Single Schedule Market (SSM), where one algorithm produces both the dispatch instructions and the nodal prices simultaneously. CMSCs are largely eliminated, and the market price predominantly reflects the dispatch decisions, improving transparency of market costs.

¹ IESO Congestion Management Settlement Credits: Backgrounder

Locational Marginal Pricing

Under the legacy market, HOEP was a single number applied system-wide, with no price signal indicating where on the grid electricity was scarce or abundant. MRP introduced Locational Marginal Pricing (LMP), with nearly 1,000 generator and load nodes going live on May 1, 2025. Each node carries a price reflecting the marginal cost of delivering energy to that location, including transmission congestion and losses.

Under MRP, non-dispatchable loads, such as Class A and B businesses, pay for their electrical consumption at the Ontario Electricity Market Price (OEMP). The OEMP is a calculated price based on the Day-Ahead Ontario Zonal Price (DA-OZP) plus the Load Forecast Deviation Adjustment (LFDA), an adjustment that accounts for the cost difference between the day-ahead demand forecast and actual real-time consumption. Generators, dispatchable loads, storage, and price-responsive loads settle at their nodal LMP in each of the Day-Ahead and Real-Time markets. Where transmission is constrained and supply cannot reach load, nodal prices rise above the zonal average; where surplus supply is blocked from export, they fall below it.

A Financially Binding Day-Ahead Market

Ontario’s previous Day-Ahead Commitment Process (DACP), introduced in 2006, was voluntary. Generators submitted forecasted availability but, since settlement occurred in real time, deviations carried no financial consequence and participation was minimal.

MRP replaced this with a financially binding Day-Ahead Market (DAM). Positions taken in the DAM settle at day-ahead prices, with real-time deviations of scheduled resources settling separately at real-time prices; a two-settlement structure that is standard across most North American ISOs and RTOs.

Year One: What Happened

Zonal Price Divergence

Across most of Ontario’s ten electrical zones, day-ahead prices have tracked each other closely through year one of MRP. While seasonal differences are visible across the province, in a typical month, the majority of zones settle within a relatively narrow band, though a few zones were consistent outliers.

Ottawa was the highest-priced zone in both the day-ahead and real-time markets from November 2025 through February 2026. This was driven by a combination of constrained import capacity into the Ottawa area, combined with increased export demand to Quebec, which intensifies during cold weather when Quebec faces tight supply conditions. When both factors align, Ottawa prices diverge sharply from the rest of the province, and in December 2025, the zone’s real-time price hit $1,281.62/MWh in a single hour, while the rest of the province sat around $183/MWh.

At the other end, the West and Northwest zones posted some of the lowest prices this winter and frequently experienced negative congestion, where local prices fell below zero. Both zones frequently generate more power than needed locally, and when their ability to export to neighbouring zones is reduced, that surplus has no outlet and prices turn negative. In January 2026, the West zone recorded a real-time congestion price of -$1,061.31/MWh, compared to the RT-OZP at $1,031.08/MWh in the same hour, which was due to a transmission outage on the Ontario-Michigan interface. Similarly, in February 2026, ongoing outages on northern transmission interfaces pushed the Northwest zone to -$694/MWh, while RT-OZP reached $978.33/MWh.

Day-Ahead and Real-Time Price Divergence

Since the implementation of MRP, we have seen regular divergence between the Day-Ahead OZP and Real-Time OZP, with the average absolute difference between them being $32/MWh across year one. Most businesses are not significantly affected by this spread as the impact is dampened by the OEMP. This mainly impacts generators, storage facilities, dispatchable loads, price-responsive loads, traders, and any other participant that settles at an LMP.

The largest single-hour spread in the dataset occurred on January 24, 2026 at 09:00, when the DAM cleared at $259.35/MWh and real-time settled at $1,327.42/MWh, a difference of $1,068. Although nearly half of all hours (49.9%) saw spreads within $15/MWh, the remaining half produced larger divergences. Over 16% of hours had spreads exceeding $50/MWh, and 542 hours (6.2% of the year), saw spreads of $100 or more.

DAM Demand Forecasting

Another consistent pattern that emerged in year one is overestimation of demand in the DAM. Analysis of hourly DAM forecast versus actual demand data from May 1, 2025 to April 30, 2026 shows the IESO’s day-ahead demand forecast exceeded actual demand in 77% of all hours over the year, with a mean over-forecast of approximately 290 MW, which is roughly 1.75% above actual demand on average.

IESO Forecast Data vs Actual Average Demand by Month, 2025-2026

The largest single-hour error in the dataset occurred on June 30, 2025, when the DAM forecasted demand was 21,647 MW, whereas actual demand was 18,821 MW, an over-forecast of 2,826 MW, or 15%.

When the DAM over-forecasts demand, it procures more supply than the system actually needs. Non-dispatchable loads are paying the costs for those day-ahead schedules under the OEMP. That excess day-ahead supply commitment can put downward pressure on real-time prices relative to day-ahead prices in those hours, contributing to the day-ahead/real-time spreads observed throughout year one. For Class A consumers, an over-forecast in a given hour also means the system peak predicted by the DAM may not materialize, adding uncertainty to peak prediction strategies.

Demand Response Activations Increased

The introduction of MRP coincided with increased demand across Ontario, where summer 2025 demand surpassed 2024’s peak demand seven times. At the same time, demand response resources secured through the Capacity Auction were activated 17 times in the 2025-2026 commitment year, 10 summer and 7 winter activations, compared to 2 activations in 2024-2025, 3 in 2023-2024, and zero in each of the two years prior.

The 17 activations reflect the more extreme weather and underlying supply tightness seen over that period, but also a structural change in how demand response is called. Under MRP, demand response resources are integrated directly into the Dispatch Scheduling Optimizer and dispatched alongside all other generation and load, giving the IESO a faster and more seamless mechanism to call on them when necessary.

What’s Ahead

Since the implementation of MRP, prices reflect transmission congestion, CMSCs are eliminated, and the Day-Ahead Market creates pre-commitment accountability, as the Renewed Market intended. At the same time, some elements that were expected to improve efficiency, particularly forecasting accuracy and convergence between day-ahead and real-time prices, remain areas of ongoing adjustment. Going forward, these patterns are likely to persist unless IESO makes further changes to its forecasting processes or market design.

For generators, storage operators, large power consumers, and traders, the renewed market prices congestion, scarcity, and locational value in the energy market itself rather than through out-of-market payments. Capturing that value, or avoiding exposure to it, depends on how participants engage with the market through nodal offer strategies, DAM participation, and accurate peak forecasting.

Workbench Energy supports large Ontario power consumers through Demand Response Direct, Peak Prediction, and IESO Settlement and Accruals services. We also provide remote operations, SCADA integration, real-time monitoring, and IESO market operations for generators and battery storage projects. Contact us to learn more.