Ontario Market Renewal 2025: Death of the Congestion Management Settlement Credit
As of May 1, 2025, Ontario’s Market Renewal Program (MRP) came into effect; a program with the goal of fixing key issues that were caused by the previously established Two Schedule System. The new system has the objective of ensuring that energy pricing reflects actual market and fixes key issues that previously plagued the grid.
For decades, Ontario’s wholesale electricity market relied on a convoluted two-schedule system that distorted price signals and masked the true costs of power. The province used a single uniform market price (HOEP – Hourly Ontario Energy Price) for energy, determined by an “unconstrained” schedule that ignored transmission bottlenecks and local constraints. Meanwhile, a separate “constrained” schedule handled the physical dispatch, respecting grid limitations. The misalignment between price and dispatch meant the market price often did not reflect the real supply cost at different locations and times. To keep the lights on, the system operator (IESO) paid out millions in Congestion Management Settlement Credits (CMSC) – side-payments to generators or consumers – whenever the dispatch had to deviate from the uniform price schedule. These out-of-market payments compensated resources for following dispatch instructions, but they also obscured true costs, shifted expenses onto all ratepayers, and created opportunities for gaming the system. By 2025, Ontario was the only jurisdiction in North America still using such a two-schedule market for energy, and the inefficiencies were evident: higher hidden costs, obscure/unclear pricing, and infrastructure investment decisions that didn’t always align with actual system needs. Reform has been a long time coming.
Key May 2025 Changes
Transformation of the Two Schedule System to a Single-Schedule Market
Replacement of the previously established two-schedule pricing system with one integrated schedule, allowing electricity prices to reflect actual conditions at every node/zone within the grid, aligning dispatch with true market costs, eliminating the need for the CMSC payment.
Day-Ahead Market Introduction
The system introduced a day-ahead pricing market, allowing participants (mostly wholesale customers) to lock in prices a day before delivery - allowing for better operations planning. This especially affects large-scale energy users like Arcelor-Mittal Dofasco in Hamilton, and Ford in Oakville.
Enhanced Real-Time Unit Commitment (ERUC)
Using advanced mathematics/algorithmic programs to improve the scheduling and dispatch from generation units throughout the day. This improves grid system reliability, reducing operational costs by more accurately committing resources based on real-time system requirements.
The Previous Pricing System: Reasons for Reform
Chief among the historical issues was the misalignment of prices with reality. Under the old two-schedule regime, prices ignored transmission congestion and losses, often resulting in market prices that did not accurately represent the actual costs of supplying electricity. This systemic mismatch not only obscured true operational costs but also undermined efficient market operations, leading to poor investment decisions. Consequently, resources were sometimes located in areas that exacerbated grid congestion, increasing overall costs.
Plot showing the area of systematic pricing mismatch plaguing the previous power system in Ontario, leading to different quantity per price unit in the dispatch schedule as compared to the market schedule.
Additionally, the Congestion Management Settlement Credits (CMSC) adjustments, designed initially to compensate for the dispatch discrepancies, evolved into a highly complex and unclear system. These credits frequently created unintended incentives for market participants to game the system, exploiting loopholes to secure payments without delivering meaningful value. This gaming further inflated costs and distorted resource allocation decisions, placing unnecessary burdens on consumers and reducing overall market transparency and fairness.
The Market Renewal Program (MRP) was designed explicitly to tackle these deep-seated problems by establishing greater transparency, streamlining market operations, and aligning incentives more effectively. By adopting a single-schedule market structure with locational pricing, the MRP enhanced visibility into actual grid conditions, thereby improving investment signals and operational efficiency. Moreover, the introduction of a day-ahead market and improved real-time unit commitment processes aimed to modernize market operations, making them more responsive to system conditions and better suited to integrate renewable energy resources, energy storage, and distributed energy resources (DERs). Ultimately, these reforms aim to reduce costs, enhance competition, and ensure reliability.
Case Study: Price Uniformity Pre-Update and Extreme Changes Following
In the old system, the existence of the CMSC led to opaque, behind-the-scenes equalization payments to various consumers leading to a uniform Ontario price that many customers paid at the same time.
In the weeks following the Market Renewal Program rollout, Ontario saw extreme examples of just how significant the shift to locational marginal pricing could be. In some instances, consumers in low-demand, generation-rich areas found themselves in the situation of paying negative prices for electricity - almost being incentivized to consume energy because of an oversupply condition. Simultaneously, consumers located in congested or transmission-constrained areas were experiencing substantial price spikes, at times paying dramatically inflated rates for electricity because local constraints limited the flow of cheaper energy into their area.
This scenario, though initially startling, underscored exactly why the market reform was necessary. The old pricing structure masked these regional and local imbalances, lumping costs into broad charges and effectively hiding congestion issues. With the introduction of locational marginal pricing, the market immediately made visible the true cost dynamics at play across the grid, revealing pockets of surplus and scarcity in real-time. This transparency not only highlighted infrastructure limitations that had previously been obscured, but it also created strong incentives for immediate operational adjustments by stakeholders.
Ultimately, this initial volatility illustrated the system's ability to send clear, actionable signals that can guide future investments and operational decisions. Areas/nodes regularly seeing negative prices may attract flexible loads, storage solutions, or even prompt reduced local generation during surplus periods. Conversely, areas/nodes experiencing regular price spikes will naturally draw investment in generation, storage capacity, or transmission infrastructure. Thus, while the initial reaction to these extremes might be one of surprise, the phenomenon represents precisely the type of market-based corrective mechanism intended by the MRP: aligning operational realities with clear economic signals to drive more efficient grid operational conditions and the data representative of that.