IESO have stated that there is a data error which impacts the gas data dispatch reported in the IESO Adequacy Reports. Note, this does not impact Power Advisory’s Weekly MRP Reports.
Adequacy Report Data Issue
Power Advisory has been looking into an IESO MRP data issue since early May, relating to the Adequacy Report and the published amounts of gas generation that are “scheduled” in the day-ahead and pre-dispatch timeframes. The issue was noted in our June 2025 webinar – and reproduced below – where we showed how pre-MRP, the IESO was publishing the amount of gas generation actually scheduled, but post-MRP, is now showing the combined gas commitments only to their combined Minimum Loading Points (MLPs).
This new “scheduled” amount has led to a gap between the forecast peak demand and the supply that the IESO has planned to dispatch to meet the demand. The image below is from the IESO’s website on June 23, 2025, with an anticipated peak of 25,073 MW and a scheduled supply amount of 20,520MW, which would mean a notable shortfall in supply (nearly 5,000 MW). The IESO has since confirmed to Power Advisory that there is a “defect” with the Adequacy Report that they are addressing.
Blocked Dispatches for Area Control Error (Dispatch Deviation Report)
According to the IESO, the Dispatch Deviation Report is “an after-the-fact summary of the number of occurrences where the IESO has taken an action that deviates from the results of the dispatch algorithm and does not impact dispatching or market settlements”. The report is important, as it is meant to highlight the number of interventions by the IESO. The monthly report notes the following:
“Subject to Market Rule, Chapter 0.7 section 3A.2.1 and section 6.6.5 this report summarizes the number of occurrences where the IESO has deviated significantly from the results of the dispatch algorithm, the action taken and the rationale for doing so. An occurrence may cover one or more intervals and all occurrences recorded in the IESO Shift Operations log are considered significant.”
The report is published monthly. If there were no deviations in dispatch, the IESO does not need to publish the report.
Power Advisory reviewed the Dispatch Deviation Reports from March 2022 to May 2025. The actions taken by the IESO are either a one-time dispatch or a blocked dispatch to resources for system reliability purposes. Blocked dispatches occur far more frequently than one-time dispatches.
During May 2025, the IESO blocked 7,025 dispatches to resources to address Area Control Error (ACE). Blocked dispatches for ACE are taken to correct an over or under generation condition. This amount of \ ACE-related interventions exceeds the entire number of blocked dispatches between March2022 and April2025 (6,477 in total). This means the IESO had to take more actions to address ACE during the first month of MRP than it had to in the previous three years. This aligns with the increased volatility we have seen since May 1. Power Advisory will continue to monitor the Dispatch Deviation Report.
Day-Ahead and Real-Time Prices
While demand may have been high, price volatility was much lower last week, with just 7 real-time Ontario Zonal Price (OZP) spikes greater than $200/MWh – with the highest price hitting $697/MWh. The peak demand last week was just 22,740 MW – more than 2,000 MW below the peak demand of 24,800MW in the previous week. Of these 7 real-time price spikes, 5 occurred on July 1st. The price spikes appear to largely be a result of sudden changes in demand from hour to hour and the general volatility of demand on a holiday like Canada Day. Note that the highest peak demand days were on July 6, July 2, followed by July 5.
The figure below shows the hourly changes in demand on July 1. Note that the morning hours see increases in demand (i.e. hour-by-hour changes in Ontario demand) by up to 1,246 MW from the previous hour.
From a forecasted versus real-time demand perspective at the peak real-time price hour, IESO slightly under forecasted real-time demand. The figure below shows 7 days of forecasted demand in the Adequacy Report for July 1, 2025 at 9 AM (i.e. this looks at the previous 7 days of forecasts for the 9 o’clock hour on July 1st). Throughout the week leading up to this hour, demand was forecasted to be 115-778 MW lower in day-ahead compared to real-time. Hence, the price spike is less related to the divergence between the day-ahead to real-time market and more related to the change in demand from hour to hour.
Similar to last week’s review, there were no negative day-ahead or real-time prices. There were few hours where the real-time Ontario price moved from well below the day-ahead price to real-time spikes significantly above it. Most days of the week are showing convergence between day-ahead and real-time prices.
OR Prices
Both real-time and day-ahead Operating Reserve (OR) prices remain elevated compared to historical averages. The average weekly day-ahead 10S price was $14.55/MW, while it was $26.90/MW in real-time. Again, this highlights that the supply stack in the OR market remain much tighter in the renewed market compared to the legacy market (as noted in previous commentaries). Both day-ahead and real-time 10S prices were typical to previous weeks’ reports. Real-time 10S prices continue to be higher than day-ahead 10S prices. Compared to last week, OR prices in day-ahead were less volatile, with the highest price spike being $123.68/MW on the first day of the week.
The average OR price was below the average energy price for all hours of the week – in line with historical patterns. Day-ahead OR prices generally closely tracked energy prices. Interestingly, days like July 4, 2025 have fairly low OR price peaks compared to OZP peak in day-ahead.
Real-time OR prices were low for several hours of the week with OR prices exhibiting less volatility compared to energy prices. As seen in the previous week, real-time OR prices are starting to largely move in tandem with real-time OZP.
Zonal Prices and Congestion
Similar to most weeks since the renewed market was launched, the Northwest and Northeast zones experienced the most congestion in day-ahead. Congestion in the Niagara and West zone was minor. The Northwest zone had the most negative congestion towards the end of the week aligning with the occurrence of real-time price spikes, reaching -$60.39/MWh in the day-ahead market. Similarly, the Northeast zone saw quite a bit of negative congestion, especially in several consecutive hours in the middle and last days of the week.
Note that negative congestion typically means there was a constraint exporting energy from a particular zone, while positive congestion is the opposite. The Northwest and Northeast zones typically post negative congestion in the day-ahead market, as there is often more supply than demand and limited transmission to export it to the major load centres in southern Ontario.
Real-time zonal prices in the Northwest and Northeast remain extremely volatile. The Northwest zone saw both negative and positive congestion. The positive congestion was on July 5, at 1 AM, while most of the negative congestion was on July 1, 2025 (Canada Day). The Northeast zone only saw negative congestion. Generally, negative congestion in the Northeast and Northwest zone was observed throughout the whole week.
And in real-time, the West zone saw very negative congestion on July 2 (1 PM) and at the end of July 5 through July 6, 2025. The West zone saw an increase in imports from Michigan by 170 MW to partially meet high demand across the province. As West zone resources at this time exceeded the West zone peak demand, it is likely that these addition of imports to the zone and constraints related to flow to other zones where most provincial demand is concentrated led to negative congestion. The negative congestion in the end of the week is largely because of the high demand (and peak demand) observed throughout the day and higher than average resource output in the West zone vs demand in the West zone.
