The fourth full week of the post-Market Renewal Program (MRP) (“renewed market”) has passed. Overall, the magnitude of real-time price volatility was lower throughout the week, with fewer hours where prices moved significantly above the marginal cost of gas-fired generation. Overall, real-time pricing in the energy market over the past week was more aligned with historical pricing in the legacy market.
Price Volatility Dampened
While previous weeks experienced numerous hours where prices moved higher than $100/MWh in real-time, price spikes were much more moderate this week – with just five hours when the real-time Ontario Zonal Price (OZP) was higher than $100/MWh. The highest OZP – which is a load-weighted average of all Locational Marginal Prices (LMPs) – was $325/MWh this past week. This is lower than the highest OZP in the previous week, which was more than $400/MWh.
The day-ahead OZP was, on average, $30.48/MWh for the entire week. This excludes day-ahead prices on May 22nd when the Day-Ahead Market (DAM) failed and there were no day-ahead prices published.
Interestingly, the day-ahead OZP was, on average, more than $9/MWh higher than the real-time price throughout the week and more than $23/MWh higher on average during the 26th and 27th.Day-ahead prices higher than real-time by $23/MWh through the 26th and 27th.
A day-ahead price higher than real-time has a few potential impacts on load customers, particularly if they are dispatchable loads. A sustained higher day-ahead price could mean that load customers would have been better off not purchasing energy in the DAM, as it would have been cheaper to buy energy in real-time. The certainty of day-ahead prices, then, can come at an additional cost (i.e. a premium) for load customers. As the renewed market evolves it will be vital for load customers to understand whether day-ahead energy pricing will come at a long-term premium compared to real-time.For generators, days with higher prices in day-ahead as compared with real-time will allow them to earn the spread between the two by buying out of their DAM schedule. For example, in Hour Ending (HE) 7 on May 27th, the Richview Reference was around $42/MWh, while the real-time price in the same hour was $0/MWh. A generator with a 10 MW schedule could “buy out” of their day-ahead schedule for $0/MWh – meaning they were essentially paid 10 MW x $42/MWh for supply that they did not have to provide. A generator could avoid being dispatched by keeping their offers at their same level as their day-ahead offers – with the lower real-time price resulting in the uneconomic offers not receiving a schedule in real-time. Due to the new two-settlement system, their overall settlement is reduced by the difference between the day-ahead and real-time price – which in this case is $0, meaning the generator is paid the same amount for its day-ahead schedule, even though it did not generate in real-time.
As virtual traders continue to participate more fully in the renewed market, we would expect that large spreads between day-ahead and real-time prices would converge. Virtual trading is a new component to the IESO-Administered Market and it may be some time before we see sustained convergence. Note that a virtual trader provides fictitious supply (demand) and can profit if the real-time price is lower (higher).
OR Prices Remain Elevated for the Fourth Week
Operating Reserve (OR) prices remain above historical averages. The day-ahead OR price last week was $25.24/MW, while the real-time price was $28.62/MW. Similar to our comments last week, 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. Nonetheless, OR prices remain above historical averages for the month of May, which in 2024 were $4.98/MW.
In addition to our comments last week, we note that the OR market is likely being impacted by the removal of Control Action Operating Reserve (CAOR), which resulted in hundreds of MWs of fictional OR supply being moved from the OR stack. With that supply removed, the OR market has likely become tighter and resulted in higher cost resources being scheduled, although there is limited publicly available data. The impact of CAOR on the OR market was previously noted by the Market Surveillance Panel (MSP) on multiple occasions. In 2016, the MSP concluded: “The reduced volume of OR offers, combined with large magnitude and frequency of forecast errors, has resulted in more frequent scheduling of Control Action Operating Reserves (CAOR) in the OR market. This is a sign of stress on the OR market.”
Congestion Remains in the Northeast and Northwest
The Northwest and Northeast zones continue to experience lower prices than other zones in both the day-ahead and real-time markets due to transmission losses and congestion. Congestion costs – which represent transmission constraints that restrict the flow of energy to load centers – is typically most extreme in the Northwest. The Northwest typically experiences negative congestion in the DAM (pushing prices lower), while sees both positive and negative congestion in the real-time market.
Similarly, the Northeast zone experienced both negative and (limited) positive congestion in real-time, while only seeing negative congestion in the DAM.
As we have noted in previous commentaries, we expected congestion to occur in the Northwest and Northeast zones due to the known transmission constraints and supply in the region. In the legacy market, shadow prices – the previous proxy for LMPs – could reach as low as -$2,000 MWh (the market floor) at this time of year when demand was low and supply from hydro facilities was highest. The introduction of financially binding LMPs, a settlement floor, demand growth and a tightening supply/demand balance appears to have removed the most extreme examples of negative pricing, for now.
Stay Tuned for Monthly Reports
Power Advisory’s analysis of the renewed market will move to monthly reports. If your organization has questions about pricing and dispatch outcomes, please do reach out to the Power Advisory team.