The third full week of the post-Market Renewal Program (MRP) (“renewed market”) has passed. The real-time market continues to experience significantly more volatility than the Day-Ahead Market (DAM) in both the energy and Operating Reserve (OR) markets, while a number of nodes posted extremely volatile Locational Marginal Prices (LMPs) during the week, particularly in real-time.
Day-Ahead Market (DAM) Failure
On May 21, the IESO notified Market Participants (MPs) that the DAM had failed for May 22nd and would be continued on May 23. A notice from the IESO noted that “the virtual trading limit has been updated to 0 MW to prevent all virtual transactions from being submitted for the DAM starting from trade date May 23, 2025 until further notice due to an IT tool issue that caused the DAM failure for trade date May 22, 2025.” The implementation of the renewed market – launched on May 1st – has gone smoothly to date from a technical perspective, although there were delays in the launching of virtual trading. Overall, we expected some hiccups as Ontario transitioned from the legacy market – which had been in place for more than 20 years – to the renewed market and early indications suggest the DAM failure was a moderate IT issue related to virtual trading. We expect the IESO will provide more details around this and other potential implementation issues with the renewed market over the coming months.
Price Volatility Lingers in the Real-Time Market
The renewed real-time market continues to experience higher volatility than the legacy market. This has been a re-occurring theme throughout our commentaries since the renewed market was launched three weeks ago. On an average weekly basis, both real-time and day-ahead prices were fairly moderate – which would be expected given the below-average demand and natural gas prices at this time of year – but real-time prices continue to spike higher than $100/MWh in most days. Typically, these price spikes are short-lived – usually 1 or 2 hours or less – but are happening on a near-daily basis and sometimes multiple times a day. There were 149 hours from2021 until May 2025 time where HOEP was greater than $200/MWh – compared to 15 hours in just the past three weeks alone when prices were greater than $200/MWH – at a time when natural gas prices were below $4/MMBtu and the marginal cost of a typical price-setting gas-fired generator is well below that level.
Prices in the day-ahead market have not experienced a similar level of volatility as real-time, which is expected given commitment and dispatch is optimized over a 24-hour period and there are no forecast errors. In contrast, the real-time market incorporates a number of variables that introduce forecast errors and other sudden changes on the grid (from both a supply and demand perspective). Nonetheless, the 27-hour Look Ahead Period (LAP) in the pre-dispatch timeframe was expected to help manage those errors, but does not appear to be fully mitigating real-time price volatility. Again, the renewed market is still very much in its infancy, and this may change over time.
Overall, the day-ahead Ontario Zonal Price (OZP) continued to be much more moderate compared to the real-time OZP – with the day-ahead OZP averaging $20.41/MWh for the week, compared to $32.36/MWh in real-time. The OZP represents the load-weighted average of all Locational Marginal Prices (LPMs).
As we have noted in other commentaries, the real-time market is largely a balancing market and the impact of high real-time prices on customers remains uncertain. If the IESO’s forecast is, on average, lower than real-time demand (for non-dispatchable customers) during the price spikes, the additional costs will flow into the Load Forecasts Deviation Adjustment (LFDA) and charged to customers. If real-time demand is lower than the IESO’s forecast, than non-dispatchable customers could be “credited” the difference – essentially, they will “earn” the amount for every MW that their real-time demand is below the day-ahead forecast and that will reduce the LFDA.
The average spread between real-time and day-ahead prices can mask the actual volatility that we continue to see. In many hours, the spread between the day-ahead and real-time price is more than $200/MWh, while the average spread between day-ahead and real-time for the week was around $12/MWh.
OR Prices Remain Elevated for the Third Week
As we have noted throughout our commentary on the renewed market, OR prices continue to be higher than historical prices at this time of year. While OR prices are typically elevated in May and June – due to the combination of many hydroelectric units operating on a “must-run” basis and lower energy prices causing limited gas commitments – the OR prices in the renewed market have been structurally higher than in the legacy market (see our previous commentaries that included a comparison).
One issue that we will investigate is the change in the OR market from the IESO’s previous voltage reduction offers. Previously, in the legacy market, the IESO offered hundreds of MWs of what was known as Control Action Operating Reserve (CAOR) at around $30/MW (there were two offers, one at $30/MW and another at $30.10 and both represented voltage reduction). In the renewed market, the IESO has incorporated an Operating Reserve Demand Curve (ORDC) that establishes high OR prices when there is limited supply. The move from hundreds of MWs with standing offers at $30/MW compared to higher ORDC prices may be a driver in the higher OR prices.
Congestion in the Northeast and Northwest
The Northwest and Northeast zones continue to experience lower prices in the DAM due to transmission losses and congestion. Congestion costs – which represent transmission constraints that restrict the flow of energy to load centers – is most extreme in the Northwest. The Northeast experienced (more moderate) congestion in the DAM as the week continued. Congestion largely disappeared in the Northwest in the latter half of the week. The Northwest also had a number of hours with positive congestion – meaning there are constraints in moving energy into the region to serve demand.
Real-time congestion has been more volatile and has also appeared in the West zone, which includes large industrial sites in Windsor and Sarnia. Looking at the Northwest in particular, congestion has been far more volatile – with congestion moving from positive to negative, sometimes in the same day.
As noted in previous commentaries, the West zone continues to experience short periods of extreme congestion and high prices. The following figure shows the zonal price in the West zone spiking to $395/ MWh in HE 4 on May 16th before coming back down close to the Richview price.
Real-Time LMPs Diverge Across the IESO-Administered Market
Price spreads in the real-time market on a nodal basis continue to have a larger spread across the IESO-Administered Market. The following graph shows that a small number of nodes experienced much higher than average Locational Marginal Prices (LMPs) than the broader market and that was more extreme in real-time compared to day-ahead. In both the DAM and real-time market, a number of nodes – across the Northeast and Northwest – continue to post lower-than average LMPs.
Price volatility can also be extreme at certain nodes. The following graph shows the average price for a small number of nodes in the Northwest zone on May 15th, HE 15. At eight of the nodes, the LMP spiked to the ceiling price of $2,000/MWh, while a number of other nearby nodes saw prices spike to more than $500/MWh. The average LMP for the hour across all of the other nodes was around $4/MWh.
Stay Tuned and Contact For Additional Support
Power Advisory’s analysis of the post-MRP will continue to evolve as more data becomes available and more information is released. While there is a significant amount of data provided by MRP, there continue to be a number of uncertainties that we are investigating. If your organization has questions, please do reach out to the Power Advisory team.