Article by
Eszter Pontenagel
On May 1st 2025, Ontario’s Independent Electricity System Operator (IESO) began its transition to a nodal market, which was successfully completed on May 8th with all major systems operational.
This transition marks a pivotal step in the IESO’s route to price transparency, locational efficiency, and congestion management as the market’s renewable energy mix evolves.
In this article, let us take a look at Ontario’s market characteristics, the renewed market design and its effect on virtual trading in the IESO.
Ontario’s IESO is one of 10 independent system operators in North America. IESO manages the power grid of the province of Ontario, serving over 5,3 million customers, and operating a wholesale market with over $23 billion worth of financial transactions per year. IESO operates in North America’s Eastern Interconnection.
As an independent system operator, Ontario’s IESO is responsible for managing and balancing the power grid in real-time while continuously developing a more efficient electricity marketplace in the province. However, Ontario’s IESO is a crown corporation (a provincial-owned enterprise) which, combined with the corporation’s history, effectively makes it the province’s load serving entity (LSE), as well. Numerous Local Distribution Companies (LDC) serve end-customers.
Today, Ontario’s IESO is a crown corporation with the responsibilities of an ISO/RTO, LSE, and a planning and procurement authority.
Ontario’s IESO operates over 30,000 km of transmission lines, allowing for imports and exports with all neighboring markets, including Canada’s Manitoba and Quebec, as well as NYISO in New York and MISO in Minnesota and Michigan.
As a net exporter, Ontario’s demand has been consistent at just over 137 TWh, with peak daily demand of around 23 GW during periods of high temperatures and humidity.
After years of stable supply, Ontario’s demand is expected to increase over the next 20 years due to decarbonization, electrification, and the emerging trend of data centers and data center hubs being established in the province.
To meet the expected surge in demand, Ontario’s IESO is working on introducing storage as a major tool to system reliability. Currently, just short of 54 MW of energy storage are connected to the grid, including batteries, flywheels, hydrogen, and compressed air facilities. Recently, IESO announced Canada’s largest storage procurements to date – 250 MW, which are expected to be operational in 2025, 739 MW by 2026, and an additional 1784 MW between 2026 and 2028. These expected storage capacities put IESO firmly at the forefront of other Canadian electric system operators (ESOs).
Much like the rest of Canada, Ontario has a predominantly renewable energy mix, with only 13% of the province’s power generation being produced from natural gas and oil. IESO has firmly embraced nuclear power, which amounts to nearly 80 TWh of electricity annually, over half of the province’s production.
After years of development of the Market Renewal Program (MRP), IESO’s new market design went into effect at the beginning of May 2025.
The Market Renewal Program (MRP) in Ontario, is a project by the IESO and its stakeholders, which was first started in 2016 with the goal of designing a market that can deliver a stable and reliable supply at the lowest cost, while preparing for the future of power on the North American continent. According to business case projections made in 2022, Ontario’s new market structure is expected to bring a net benefit of $700 million over the first 10 years after its implementation.
IESO's market reform introduced large-scale changes to settlement, unit commitment and a newly designed nodal pricing system for the day-ahead and real-time markets. Apart from introducing a virtual day-ahead market, the market renewal program led to numerous changes for physical traders and power producers, which will not be discussed in this article. Please get in touch with our experts directly if you’re interested in trading physical power in Ontario’s IESO →
Below, our experts discuss the changes affecting virtual traders in Ontario:
Replacing the legacy scheduling model, discussed below, addresses the IESO’s long-standing issues with misalignment between dispatch and price.
Under the MRP, IESO moved from the legacy, voluntary day-ahead clearing process, to a renewed, financially binding day-ahead market.
The legacy out-of-market payments to account for congestion during the double schedule market are now replaced by 973 separate nodal prices for day-ahead and real-time markets, which account for the locational cost of congestion.
During Q1 of 2025, Ontario’s IESO tested all MRP systems in a sandbox environment, where they allowed market participants to get acquainted with the renewed systems. As final preparation, the IESO performed systems health checks in April and confirmed the launch date.
During the launch, the day-ahead market was unavailable on May 1st and 2nd, while IESO established the new real-time market. Additionally, market participants were required to submit dispatch data for both the legacy and the renewed markets on April 30th and May 1st.
The launch was a smooth process overall, with the nodal day-ahead market opening on May 2nd, and the renewed settlement system being in effect on May 3rd.
The IESO experienced a few technical glitches, mostly to non-essential communication systems, which were resolved without complications for market participants.
“Ontario’s renewed electricity market is now live — a major milestone in the Independent Electricity System Operator’s (IESO) work to modernize the province’s electricity market.” - published IESO on LinkedIn.
Let us take a look at the changes to virtual markets and the newly introduced systems, which affect how virtual traders can operate in IESO:
Under IESO’s legacy scheduling system, one schedule was used to calculate a uniform market price for the whole province, which ignored congestion on the grid, but was still utilized to settle financial transactions within the IESO.
To account for grid constraints, a second schedule was used to manage dispatching. This schedule produced redundant, out-of-market payments for congestion (CMSC).
Under the legacy system, it was possible for generators to be cleared for higher production levels under the first schedule, only to have their actual production limited when congestion was taken into consideration under the second schedule.
Ontario’s renewed single schedule market dispatches the system and calculates locational prices at 973 nodes across the province, which account for local weather, supply, demand, and grid conditions.
By introducing nodal pricing, Ontario’s IESO is following the default market design set by US independent system operators. Currently, IESO is the only Canadian ISO to use nodal LMPs, with Alberta’s currently AESO utilizing zonal pricing.
By default, locational marginal pricing reflects 3 main components in a single price: the cost to produce the commodity, the cost of transporting it across the grid, and the grid conditions at the time of transportation (e.g. congestion and loss).
In Ontario, 973 individual nodes reflect generation and load locations across the province:
The redesigned market pricing is expected to enhance efficiency, competition and transparency for market participants.
The renewed market design in Ontario formally introduced a financially binding day-ahead market to boost convergence between real-time and day-ahead prices. The formal day-ahead market replaced the legacy day-ahead commitment process (DACP), which, despite its name, lacked the financial commitments found in other ISOs’ market design.
Under the legacy DACP, generators submitted their forecasted availability and intended output, but since settlements occurred in real-time, deviations between forecasted and actual production were not penalized.
IESO’s new DAM offers generators more revenue predictability and provides the system operator with a clearer picture of resource availability. The new market supports a two-settlement system, which exposes participants to both day-ahead and real-time price signals.
Ultimately, IESO expects the new DAM to encourage broader participation and reduce price volatility. With hourly pricing in the DAM and continued five-minute pricing in the real-time market across all nodes, the system is expected to foster more competitive dynamics and improve the efficiency of price formation.
To further boost liquidity on the newly established DAM, IESO introduced a financially binding virtual market. The virtual day-ahead market in Ontario is zonal, mirroring the design in NYISO and ISO-NE, with 9 tradeable virtual transaction zones. In the virtual market, the Southwest and Bruce zones have been combined to better balance load and supply in the region.
Ontario’s zonal prices are calculated as hourly, load-weighted averages of all non-dispatchable LMP nodes in the zone’s area.
No, Ontario’s IESO does not offer an internal FTRs product for hedging congestion risk. While the IESO has not commented on plans to introduce a similar product in the future, we have observed similar market renewal programs in some of the USA’s largest ISOs start out with a zonal virtual market, which was later transitioned to nodal pricing.
Financial Transmission Rights (FTRs) in IESO are limited to cross-border points (locally known as interties) and are settled against the day-ahead congestion prices, giving them an active role in managing congestion risk.
IESO utilizes a dynamic settlement pricing for cross-border transactions with Quebec, MISO, NYISO, and PJM:
Ontario has aligned its market design with well-established practices already in use across other independent system operators across North America. By introducing a financially binding day-ahead market, virtual transactions, enhanced congestion pricing, and numerous updates affecting physical market participants, IESO is laying the groundwork for not only smoother operations today, but also for a future where additional market products can be implemented as the system matures.
If you’re interested in trading virtually in Ontario’s new market structure, our team is ready to help you navigate your entry with confidence. Get in touch with our experts here →
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Disclaimer: Time2Market ApS is not responsible for the completeness, accuracy, and actuality of the information provided. This article is intended for informational purposes only and should not be considered business or legal advice. The energy industry is extremely dynamic and counterparties change their requirements frequently. As a result, information discussed on this page is subject to change without notice.
This page has last been updated on
May 16, 2025
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