By looking back over the past fourteen years, we can see clear long-term trends, periods of market shock, and a total system cost that has gradually increased. Then, using what we’ve learned, we can explore several possible scenarios for future rates over the next three years. 

A Noisy Monthly Picture that Reveals a Clear Long-Term Pattern

When we examine commodity (green) and Global Adjustment (yellow) on a monthly basis, the data appears noisy. Monthly variability in natural gas prices, supply availability, contract payments, and system demand leads to wild swings. It can be difficult to see any stable relationship in numbers that move so frequently.

However, when we plot a 12-month centred rolling average, a much clearer pattern emerges. (Note, we used a centred rolling average instead of a trailing average to ensure we accurately reflected the significant increase in commodity rates seen in the last 6 months). 

Commodity and GA move in opposite directions because they work together to fill the total revenue requirement of the system. When commodity prices are low, GA rises to ensure generators still receive their contracted amounts. When commodity prices rise – typically because natural gas sets a higher marginal price – GA falls because the market is already providing more of the required revenue.

This relationship becomes particularly visible during shock periods. One example is the spike in commodity rates in 2022, caused in part by the global natural gas crisis following Russia’s invasion of Ukraine. As commodity rose sharply, GA dropped. More recently, in 2025, Ontario’s move to the Day-Ahead Market combined with unusually cold winter temperatures and generator refurbishments (especially amongst nuclear facilities) pushed commodity prices higher again, and GA responded by falling.

While the monthly data appears chaotic, the rolling average reveals a consistent long-term structure: commodity volatility absorbs short-term events, while GA adjusts to keep the overall system whole.

The Total Cost of the System Has Been Rising for More Than a Decade

When we look at the combined cost of commodity and GA, a long-term upward trend becomes visible. From 2011 through late 2020, total electricity costs rose steadily as Ontario paid for contracted generation, system upgrades, and new capacity resources.

In 2021, the combined rate drops significantly – but this was not the result of falling system costs. Instead, the provincial government shifted a portion of the GA cost bucket into the tax base, reducing the GA line on customer bills even though the underlying obligation to generators remained unchanged. In other words, the accounting changed, not the economics.

Following that reclassification, the combined rate began rising again, reflecting the same structural pressures seen before: aging assets requiring refurbishment, contracted resources with escalating payments, and growing capacity needs across the province. The system costs that drive GA and commodity continue to increase over time, regardless of which line item they appear under.

Looking Forward: Three Indicative Scenarios for the Next Three Years

While no one can predict electricity markets with certainty – and EnPowered does not provide commodity forecasts – we can outline several illustrative pathways based on system fundamentals and historical responses to major events. These scenarios are designed to help businesses understand how total electricity costs, commodity rates, and Global Adjustment may evolve under different conditions.

Across all three, one insight remains consistent: even in the most extreme case, average GA over a 12-month period never falls to zero, because the overall system costs are expected to continue rising as the system continues to sign new contracts with generators and as Ontario’s grid load continues to increase. This doesn’t mean we won’t see months with zero or negative GA values, but the average GA over a year can be expected to remain positive.

Scenario 1: A Stable System With Strong Nuclear and Renewables

In the first scenario, Ontario’s nuclear refurbishments remain on schedule and future renewable additions continue. These generators supply relatively low-cost baseload, replacing more expensive natural-gas-fired generation as our main baseload supply. This reduces Ontario’s reliance on gas, reducing overall commodity rates.

Under these conditions:

• The commodity rate experiences an initial shock (similar to early 2022) due to the perfect storm of a new market structure, reduced supply from nuclear refurbishments, and increased demand from a colder winter, but then rates settle back down at a moderate rate.
• GA rises as commodity stabilizes, maintaining overall system revenue.
• The Day-Ahead Market becomes more orderly as fewer high-priced gas hours set the marginal price.
• Winter volatility remains, but does not dominate the annual profile as future winters are not as cold as the 2025-2026 winter.

This scenario represents a return to stability, though not to the low commodity prices of the mid-2010s as we show commodity rates settling around 5 cents/kWh. In this scenario, global adjustment rates start around 5 cents/kWh before rising to 9 cents/kWh after 3 years.

Scenario 2: Delayed Nuclear, Continued Gas Reliance, and More Harsh Winters

In the second scenario, nuclear refurbishments proceed more slowly than expected. Ontario remains reliant on natural gas to cover both peak and baseload needs, and we experience several more colder-than-average winters similar to the 2025-2026 winter.

Under this path:

• Commodity prices drop slightly as the initial price shock ends, but they remain elevated as gas generation continues to set prices in the day ahead markets.
• Repeated cold winters result in high commodity prices during winter months, which drives up the average commodity price each year.
• The total combined rate still increases steadily as additional generation is added to the system to increase supply.
• Even as commodity prices remain high year-over-year, GA prices remain stable as overall system rates increase.

This scenario reflects the conditions experienced in the 2025-2026 winter season reasonably well: structural reliance on gas, combined with seasonal volatility, pushing commodity higher. However, the difference between Scenario 1 and 2 ultimately depends on whether this past winter was a unique “perfect storm” of circumstances (a new market structure, decreased supply, and increased demand) or whether this can be expected to repeat again next winter. In this scenario, commodity averages between 6-10 cents/kWh and GA stays flat between 5-6 cents/kWh.

Scenario 3: A Major Global Shock Drives Prices Much Higher

In the final scenario, Ontario continues relying on gas while the global energy market experiences another major disruption – similar to or worse than the surge in gas prices resulting from the Ukraine war in 2022. This could be geopolitical, supply-chain driven, or related to rapid shifts in LNG demand worldwide.

In this environment:

• Similar to scenario 2, commodity prices drop slightly after the initial price shock, but they remain elevated as gas generation continues to set prices in the day ahead markets.
• Commodity then spikes even higher over future years as natural gas prices rise fast and continue to set prices in the day ahead markets.
• Even in this extreme scenario, GA falls but never reaches zero on average over a 12 month period. This is because overall system costs continue to increase steadily as additional supply is contracted. 

This scenario is unlikely to materialize every year, especially given that the North American natural gas market is largely insulated from global price shocks, but it’s helpful to model this outlier scenario to show what effects it would have on commodity and GA rates. Importantly, although we would expect to see months with low or even negative GA rates, the overall 12 month average would remain positive. 

What This Means for Ontario Businesses

Across all historical periods and future scenarios, one finding is consistent: the combined cost of commodity and GA continues to rise over time, regardless of the short-term fluctuations between the two.

While many businesses are focused on whether GA or commodity is rising in a particular month, the more important finding is that total costs continue to climb. With this increased market volatility, the incentive to invest in flexible assets such as batteries or generators only increases.

As we highlighted in our recent articles, customers who can shift load, operate generators strategically, or cycle batteries daily will increasingly benefit from these hourly and monthly price dynamics. Ontario’s market is changing – but it is also becoming more transparent, more price-responsive, and more rewarding for businesses that adapt.

Ontario’s electricity market continues to evolve, and the past year has exposed just how valuable flexibility has become for customers. In an earlier article, we showed that even as market rates change, Demand Response activations have shifted, and the Day-Ahead market has launched, the stacked value of flexible assets still averages close to $400,000 per MW-year. The fundamentals remain strong, but the methods of participation are changing.

Today, customers can no longer rely on a few annual peaks or a once-a-season activation to drive their savings. Instead, value increasingly appears in the hourly price signals and daily spreads that shape Ontario’s new market reality. And the way each customer participates depends heavily on the type of assets they operate.

Below, we break down three common asset types – generators, batteries, and BAS-driven facilities – and illustrate how each can capture meaningful value through smart, threshold-based participation. Our analyses assume a 1MW load and covers the last 9 months (May 2025 to January 2026), as that is the period since Ontario’s IESO introduced major changes through their Market Renewal Program. 

1. Generator and CHP Customers: Run When Prices Exceed Production Costs

For businesses with generators, particularly those operating Combined Heat and Power (CHP) units, the most effective strategy is to link generator runtime directly to electricity prices rather than fixed schedules. Most CHP units have a well-understood cost of production – often around $80/MWh when fuel and maintenance are included, although this can vary between $70-$100/MWh depending on generator efficiency and fuel costs. When grid prices rise above this cost, it becomes economically advantageous to run.

A practical approach is to set a price threshold of $150/MWh, allowing the generator to start whenever the market exceeds that level and continue running for as long as conditions justify it. In our analysis, we constrain each response to a minimum of three hours and a maximum of twenty-four hours to reflect realistic operational preferences and warm-up requirements.

Using these parameters, generators would have been called into service over 70 unique days over the analysis period, operating a cumulative 491 hours. During these hours, avoiding grid electricity would have saved $126,339 in electricity costs. Fuel and operating expenses for the same period totaled $39,280, resulting in net savings of $87,059 per MW. If we extend this to a full year of savings, instead of the 9 months in this analysis, that would equate to net savings of $116,079 per MW per year. 

This example illustrates how even a simple, rule-based dispatch strategy – run when electricity exceeds your production cost – can produce strong, repeatable results in today’s volatile price environment.

2. BESS Customers: Daily Arbitrage Within Warranty Limits

Battery systems participate in the market differently. Their advantage comes not from avoiding high-priced hours occasionally, but from cycling regularly to exploit the spread between low and high prices. With the launch of the Day-Ahead market, these spreads have become more predictable and actionable, giving batteries new opportunities nearly every day of the year.

A typical operational framework is to allow the battery to charge overnight during the cheapest hours and discharge during the most expensive hours of the day. To remain within battery capacity limitations and warranty constraints, the asset in our analysis can respond for up to four hours per day.

Using these parameters, and assuming a marginal degradation and charging cost of $47/MWh, a 1 MW battery would have responded every day where the price spread was large (277 days in the analysis period), cycling across 1,107hours in total. These operations would have produced $129,146 in electricity savings through daily arbitrage. After accounting for $52,571 in charging costs, the system would have achieved net savings of $76,575 per MW. If we extend this to a full year of savings, instead of the 9 months in this analysis, that would equate to net savings of $102,100 per MW per year. 

Importantly, this value is independent of GA or DR programs – meaning batteries continue to create strong returns even before layered program participation is added.

3. BAS Customers: Shift Load When Prices Rise

Building Automation System (BAS) driven facilities – campuses, hospitals, and industrial sites – typically rely on electric boilers, chillers, HVAC loads, and other flexible systems that can shift or shed load without disrupting operations. As electricity prices have become more volatile, these businesses can increasingly benefit from fuel switching or load shifting strategies.

A common and highly effective approach is to shift boiler load from electricity to natural gas when electricity prices exceed a site-specific breakeven point. In our scenario, we assume customers switch whenever prices rise above $150/MWh, reflecting the cost of operating a natural-gas boiler at approximately $70/MWh equivalent input cost – although this would vary for each asset. Unlike generators or batteries, boilers can often shift instantly and for long durations, so we allow a maximum response of twenty-four hours and no minimum response duration.

Using these parameters, a 1 MW boiler would have shifted load over 70 unique days over the analysis period, covering 522 hours in total. Avoiding grid purchases during these hours would have saved $131,368 in electricity costs. The cost of producing the same thermal output using natural gas totaled $36,540, yielding net savings of $94,828 per MW. If we extend this to a full year of savings, instead of the 9 months in this analysis, that would equate to net savings of $126,437 per MW per year. 

For many BAS customers, this strategy requires no new hardware – only a willingness to operate differently in response to market conditions.

Across All Customer Types, Flexibility Now Drives the Majority of Value

Although generators, batteries, and BAS facilities participate differently, a unifying theme emerges: flexibility is becoming the most important determinant of value in Ontario’s electricity market.

• Generators earn more by linking runtime to price thresholds rather than fixed schedules.

• Batteries achieve daily savings through consistent arbitrage, not just seasonal peaks.

• BAS customers unlock substantial value through real-time fuel switching and load shifting.

Across all three groups, the customers who succeed are those who treat flexibility as an operational capability and not an afterthought. Hourly participation – once optional – is becoming essential.

Ready to Capture More Value With Your Asset?

Whether you operate a CHP system, a battery, or a BAS-controlled facility, your success in the modern market depends on using your assets more intelligently and more flexibly. EnPowered helps customers automate these strategies, apply optimized thresholds, and participate across all available programs with minimal manual effort.

If you’d like help evaluating your asset’s potential, modeling your thresholds, or implementing automated controls, our team is ready to assist.

The short answer, based on more than a decade of data, is yes. But the long answer matters even more: batteries remain one of the most consistently valuable energy investments not because markets are stable, but because batteries themselves are flexible enough to thrive in unstable conditions.

And when backed by the right operational strategy, that flexibility becomes a long-term competitive advantage.

A Market That Appears Turbulent, Yet Produces Remarkably Consistent Value

Ontario’s electricity programs look unpredictable when viewed individually. Global Adjustment savings surged in the late 2010s before contracting. Demand Response activations were practically non-existent for a decade, before becoming extremely common in the past year. And until recently, the commodity market offered only uncertain and risky arbitrage opportunities through real-time prices.

But starting in May 2026, Ontario introduced a Day-Ahead market, which created a more structured and predictable environment for price-based decision-making. Batteries now have clearer signals and more opportunities to respond when wholesale prices spike. Importantly, these Day-Ahead opportunities are incremental value layered on top of existing programs.

When you combine all these components, the long-term picture becomes clearer. Over the past 15 years, the total annual value of a well-controlled megawatt of storage has remained anchored around $400,000 per MW per year, even as individual programs expanded, contracted, or fundamentally changed.

This stability does not come from the market itself. It comes from the asset’s ability to adapt to changing market conditions.

The Flexibility of Batteries Is Their Superpower

Generators have long served as backup assets and have historically been the better economic decision, but their relative inflexibility is starting to limit their ability to unlock savings. They typically provide resiliency and, depending on configuration, may participate in major grid programs such as demand response (DR) or the industrial conservation initiative. However, their operating profile is rigid, they take more time to start, and they cannot economically cycle once or multiple times per day.

Batteries are different. They can respond instantly, discharge multiple times a day, and adapt to whatever opportunities the market presents. This is why even during periods of significant market change – whether global adjustment (GA) reform, evolving DR rules, or the introduction of the Day-Ahead market – the total value captured by a battery remains high. This became particularly relevant in 2025, when the value of responding to daily price signals in the Day-Ahead market increased significantly. Now, participating in the Day-Ahead markets can be worth nearly as much as participating in Demand Response.  

A battery’s savings are not tied to one program. They come from every opportunity the market offers:

• Global Adjustment
• DR capacity payments
• DR activations
• Day-Ahead events
• Real-time price spikes
• Rate class alterations
• Backup value during outages

Because the system consistently rewards fast, flexible assets, batteries remain well-positioned regardless of how the market evolves. Flexibility is not just a feature – it is the foundation of long-term value.

Success Requires Active Management, Not Passive Operation

A decade ago, investing in a generator or battery was often perceived as a “set it and forget it” decision. Peak predictions were more predictable, DR events were rare, and the real-time market had almost no daily swings worth chasing. The asset largely followed a seasonal schedule and still performed adequately. Many customers felt that they could manage their assets manually and on their own. 

That era is over.

Today’s market requires active, continuous, and highly informed operation. Batteries must be dispatched strategically – not just a few times per season, but often multiple times a week or even multiple times a day. Savings come from reading the market, forecasting conditions, understanding price formation, and making the right decision in the right five-minute interval.

Companies that rely on static operation, incomplete forecasting, or limited-program participation leave a substantial portion of their savings unrealized. The asset may be capable, but the controls are not.

EnPowered has invested heavily into bridging that gap. We have worked with our customers and spent years designing systems, forecasts, and control strategies that allow batteries to participate fully across every program, every event, and every price trigger. This is the difference between capturing the theoretical full-stack value and achieving it consistently in real operations.

New Opportunities Are Emerging, such as Utility-Led DR Programs

Another important development is happening quietly but significantly across Ontario. Local utilities are beginning to introduce their own Distribution-Level Demand Response programs, separate from the provincial IESO-administered DR programs. These offer customers new incentives to reduce load or discharge behind-the-meter assets during local system constraints.

This is a major step forward for battery economics. Distribution-level DR programs effectively create a new layer of value – one that batteries are particularly well-suited to capture due to their speed, controllability, and reliability.

As more utilities implement these programs, batteries will have access to additional earnings streams that generators may not qualify for. This adds yet another reason why the future value of storage assets remains strong even as the broader energy landscape continues evolving.

What This Means for Organizations Evaluating Storage or Backup Power Solutions

If your organization is exploring the business case for a new battery or generator, the message is straightforward: the market will continue to change, but the value of flexibility will not. Batteries deliver flexibility better than any other asset, and that flexibility is exactly what the Ontario grid rewards.

If you already own a battery or generator, the question becomes whether you are unlocking every available opportunity. With the right controls, existing assets can perform far better than many companies realize. With passive or limited operation, even the best hardware will underperform.

In a market defined by change, strategy – not hardware – is what drives long-term results.

Considering a Battery? Already Have One? Let’s Talk.

Whether you’re evaluating an investment or looking to improve the performance of an existing asset, EnPowered can help you understand the full stacked value, model your expected ROI, and manage your system to participate in every relevant opportunity. The historical data is clear: storage assets offer stable, meaningful returns when operated strategically, and those returns are poised to grow as new programs emerge.

If you want to explore what this could look like for your organization, we’re here to help.

The Ontario grid is in need of additional capacity as demand continues to grow in the province, and we have seen that reflected in increased targets for the capacity auctions. From the 2022 to 2026 auctions there was an increase of 800MW (80%) in summer and 700MW (140%) in winter. This alone doesn’t explain the significant rise in prices that we saw in this latest auction however. 

Prices in prior auctions had been rising, but gradually. Nothing in the historical trend suggested a move of this magnitude in a single year. To understand what happened, it is necessary to look beyond the clearing price and examine who showed up to supply capacity, who did not, and how those shifts changed the balance of supply and demand. 

A Brief Look Back at Auction Pricing

From 2021 through 2025, capacity clearing prices followed a relatively stable path. The value of 1MW of capacity during the summer season (May to October) increased from just under $25,000/MW-season in 2021 to over $40,000/MW-season by 2025. The value of 1MW during the winter season (November to April) also increased over time but remained well below summer levels, starting at $0 in 2021 and increasing to roughly $15,000/MW-season from 2023-2025.

The latest auction broke that pattern. Prices rose dramatically, especially winter prices which had historically lagged summer prices but now cleared above summer for the first time.

When prices move this quickly, it is usually a signal that something more fundamental has changed. In this case, that change was not on the demand side alone, but in how supply entered – or exited – the auction.

Who Supplied the Auction – and Who Didn’t

Generators: Choosing Certainty Over Auctions

In earlier capacity auctions, generators played an important role by providing a meaningful block of 200-300MW of relatively predictable capacity. That supply applied downward pressure on clearing prices, particularly during winter obligation periods.

In the latest auction, generator participation disappeared entirely. The effect on the auction was immediate. With generator supply removed, the remaining participants were competing to fill a much smaller pool of available capacity, putting upward pressure on prices.

Imports: A Vanishing Source of Supply

Beginning in the 2023 auction Imports have provided significant supplemental supply in the capacity auction, though their participation has always been sensitive to external market conditions and limits on the amount of imports accepted into the auction. In the past few auctions, they’ve supplied roughly 600MW during the summer period and 150MW in the winter period. In the latest auction, however, a number of importers left the market. Summer import capacity declined slightly only because Hydro Quebec significantly increased its exports to Ontario to counteract the disappearance of other importers, however winter import participation disappeared entirely.

Regardless of the reasons, the outcome was straightforward: another source of flexible supply was no longer available. Combined with the loss of generator participation, this further tightened the market.

Aggregators and Direct Physical Participants: Holding Their Ground

While generators and imports pulled back, Demand Response aggregators (companies that aggregate the load of hundreds of smaller companies) and direct physical participants (large companies that directly opt-in their load to the auction) remained relatively consistent. Their participation fluctuated between obligation periods, but there was no broad withdrawal from the market.

This point is important. The price increase was not driven by aggregators reducing supply or exiting the auction. Instead, prices rose because other sources of supply declined while demand continued to grow.

Direct Virtual Participants: A Quiet but Important Shift

One of the more interesting changes in recent auctions has been the growth of direct virtual participation – companies choosing to directly participate in the capacity auction without having to be a physical market participant (which has additional regulatory burdens). Historically, this category represented a very small portion of the auction. In this latest auction, direct virtual participants accounted for a noticeably larger share of cleared capacity, particularly in the winter obligation period.

This reflects a growing number of customers choosing to participate directly rather than through an aggregator. Doing so requires confidence in forecasting, operational flexibility, and an understanding of program requirements. The increase suggests that more customers are engaging deeply with the mechanics of the capacity program.

At the same time, direct participation shifts risk onto the customer. As prices rise, the cost of underperformance or administrative error increases as well, making execution more important than ever.

Why Prices Rose So Sharply

When these participation changes are viewed together, the price outcome becomes easier to explain. Demand for capacity has continued to increase as system planners looked to secure more short-term capacity. At the same time, two historically important sources of supply – generators and imports – reduced or eliminated their participation in the auction.

With fewer megawatts available to meet higher demand, clearing prices rose to reflect the scarcity of dependable capacity. This was not a temporary distortion, but a market response to a changed supply mix.

Despite this significant increase in clearing prices, capacity secured through the capacity auction remains competitive. The Ontario IESO (the independent electricity system operator) recently completed a long-term procurement process which saw the cheapest supply, provided by energy storage resources, clearing at $672/MW-day. So, although clearing prices increased a lot this year, the secured capacity remains economic and tied to near-term system needs without longer term contractual commitments.

Execution Still Matters More Than Structure

Ontario’s Demand Response program is built around performance. Participants must forecast their ability to respond accurately, respond when called, and pass verification and testing requirements each obligation period.

EnPowered has passed every test to date. In a higher-priced environment, that track record matters. As clearing prices increase, the downside of missed performance grows as well, making reliable execution a central consideration for customers evaluating their options.

Over the past three years, EnPowered has grown steadily, doubling its customer base each year and becoming the fastest-growing Demand Response aggregator in Ontario. This growth has occurred alongside increasing market complexity and higher performance expectations.

Importantly, many customers have chosen to remain with EnPowered even as direct participation has become more common. In a market where prices – and penalties – are rising, customers are placing greater value on experience, execution, and the ability to consistently meet program requirements.

What This Means Going Forward

The latest auction results suggest that Ontario’s capacity market has moved into a new phase. Higher prices reflect higher value, but also a tighter and more selective supply environment.

The recent increase in clearing prices should be viewed less as a one-off event and more as a signal that the market has changed. Supply has shifted, demand has grown, and execution has become more valuable.

For customers participating in Ontario’s Demand Response program, understanding these dynamics – and choosing a strategy that aligns with their operational realities – will matter far more than chasing t  he headline clearing price.

The answer lies in a sharp and unusual spike in Ontario electricity prices over the past two months. November – typically one of the lowest-cost months of the year – ended with an average wholesale electricity price of $82/MWh, higher than every other month in 2025. During periods of tight system conditions, some real-time prices exceeded $500/MWh, driving unexpected cost increases for businesses exposed to wholesale pricing.

For many greenhouses and industrial operations, this has meant an unexpected increase in operating costs that have added significant strain to operating budgets. The story behind today’s price spikes comes down to three major forces working together – two of them typical for winter, and one that is far more impactful this year. 

To understand what is driving these price spikes, it’s important to first understand how Ontario electricity prices are set in Ontario for every hour. Below, we will explain how Ontario’s price-setting mechanisms work, break down what is driving these price spikes, and then outline what may change as we move deeper into winter.

How Ontario Electricity Prices Are Set

Ontario’s day-ahead and real-time prices are set by the highest-cost resource needed to supply the next unit of electricity.

This means that for every hour of the day, a market auction is held where supply is matched to demand in order to set the price for that hour. Every supplier that supplies electricity during that hour is then paid that market clearing price regardless of what their bid was. As a result:

• If low marginal cost nuclear and renewables are available, they take on the majority of the load, and encourage lower and more stable electricity prices.
• If Ontario demand is high and the system is forced to call on natural gas generators, especially aging or inefficient generators, their high marginal costs become the market-clearing price for that hour.

For example, a simplified bidding model is outlined below. The Ontario market is very similar to this, with electricity prices set for each hour of the day, but of course there are far more bidders and added complexity in the real market.

In this simplified scenario, the Ontario demand for the hour is 18GW (18,000MW). The market first selects all of the low or no marginal cost suppliers such as nuclear and renewables, it then selects the lowest cost marginal suppliers such as hydro and more efficient natural gas plants until it reaches enough supply to match demand. In this scenario, supply matches demand at a clearing price of $40/MWh. 

Note, all of the rates shown in this scenario are illustrative only.

Using this simplified scenario, we can now start to adjust some assumptions to show how that would impact Ontario electricity prices. For example, if the hourly demand increases from 18GW to 21GW on a cold winter day, then the market has to select additional gas plants until supply matches demand again. In this scenario, that occurs when the clearing price reaches $70/MWh.

Or, if we assume that natural gas prices increase this would naturally increase the cost of electricity produced by natural gas power plants. As shown below, even if demand stays at 21GW the clearing price now has to reach $100/MWh before supply meets demand.

Or, if some of the nuclear supply and the cheaper natural gas supply goes offline for scheduled maintenance, the cost curve adjusts. Now, with fewer lost cost suppliers available, higher cost suppliers must be called upon in order to match supply and demand. As a result, the clearing price has to reach $120/MWh for this given hour.

With an understanding of this simplified scenario, we can now understand how the market changes in the real world affects Ontario electricity prices.

1. Higher Winter Electricity Demand in Ontario

Every year, electricity demand rises naturally as temperatures drop. Facilities use more heating, ventilation systems run harder, and lighting loads extend into longer evenings.

The IESO’s demand forecasts shows exactly this:

• Rising demand through November,
• A small dip during the holiday period, and
• Another climb as we move into January.

This pattern happens every year, but usage is higher this year. In previous years, it was rare for usage to reach 21,000MW in the winter, however we have already seen usage exceeding 21,000MW in November and December with usage expected to climb as high as 23,000MW in January. 

As outlined above, as demand increases the market has to select higher cost suppliers in order to match supply and demand, but this does not fully explain the scale of the price jump we’ve seen.

IESO Forecast for Ontario Demand, October 2025 to January 2026

2. Higher Natural Gas Prices

Every year, natural gas prices rise as we enter the winter months and more natural gas is consumed by businesses and homeowners for heating. 

Natural gas plays an important role in Ontario’s electricity supply mix. When gas prices rise, the cost of generating electricity rises with them. Even efficient plants become more expensive to operate, and less efficient plants – often the ones called on during tighter system conditions – can become dramatically more costly.

This winter, gas prices have increased and are relatively high compared to most of the past 10 years, however they are still well below the prices we saw in 2022 and 2008. 

As outlined above, higher natural gas prices forces natural gas power plants to increase their bids in the Ontario market. If these natural gas suppliers are called on to supply electricity, this then sets a higher marginal price for electricity as well. This still doesn’t fully explain the extreme price volatility we’ve seen in the past two months however.

Henry Hub Natural Gas Prices ($/MMBtu)

3. Generator Outages and Constrained Supply in Ontario

While rising demand and higher fuel costs provide the backdrop, the real story behind the price surge in the past two months is constrained supply.

Over the past two months, Ontario has had several generators shut down for scheduled maintenance, specifically including nuclear units and high-efficiency combined-cycle natural gas units. When these lower-cost assets are offline, the grid is forced to lean on more expensive, less efficient generators to meet demand – exactly the kind of conditions that produce sharp increases in clearing prices.

This maintenance was scheduled for October/November because demand is usually low in Ontario during these months, but we have experienced a colder than usual start to the winter which is seeing higher demand than originally expected.

Thankfully, when comparing the scheduled outages for December 8th and December 31st, we can see that a significant portion of these facilities are expected to be coming back online in the coming weeks. Specifically, while we are still expecting 3,500MW of nuclear to be offline for refurbishment, nearly 4,000MW of supply is expected to come back online by the end of December.

IESO Historical and Projected Outages

What To Expect Moving Forward

As we head into January, we can expect natural gas prices to either stay the same or potentially increase slightly and for electricity demand to increase by another 1-3GW. Both of these will apply even more upward pressure on Ontario electricity prices.

However, we can also expect nearly 4GW of supply to turn back on after their scheduled maintenance is completed. This additional supply should relieve some of the system tightness that has contributed to the highest price spikes.

As nuclear and efficient gas units come back online the grid has more low-cost options available each hour, meaning it will have less reliance on inefficient peaking generators. 

It’s impossible to know with certainty what this will mean for Ontario electricity prices in the near future, as this would require us to know the exact bidding strategies of every supplier in Ontario, however we can return to our simplified bidding model to understand the variables.

If we assume that Ontario demand will climb as high as 23GW in January, and that natural gas prices will increase slightly, then under a constrained supply mix this would require us to use all of the supply available to match demand with market clearing prices climbing to $130/MWh.

However, with 4GW of supply returning by the end of December, this will significantly alter the supply mix available in the Ontario market. In our simplified scenario, this would drop the market clearing price to $100/MWh despite the same increase in natural gas prices and significant increase in electricity demand. 

The Bottom Line

Ontario’s recent surge in electricity prices came from a combination of higher demand, higher natural gas prices, and tighter supply from generator outages.

As more generation returns to service in the coming weeks, Ontario will enter January in a stronger supply position than the past two months. While we cannot predict Ontario electricity prices with certainty, the conditions that produced the most significant volatility are improving.

That means businesses should experience a more moderate and more stable pricing environment compared to the severe tightness seen through late fall.

If you’d like help understanding what these market conditions mean for your facility – or how to manage cost exposure during volatility – EnPowered is here to help.

These sectors already operate on tight margins. Now, electricity volatility is adding new pressure—but also new opportunity.

And Ontario’s shift to the Day Ahead Market (DAM) is creating an advantage for businesses willing to embrace it.

A Market Shift That Changes Everything

As of May 1, 2025, Ontario businesses can see tomorrow’s electricity prices today – hour by hour.

That level of forward price certainty simply didn’t exist before. Now, instead of feverishly trying to respond to real-time price information and simply reacting to volatile prices after the fact, businesses can utilize valuable costing information for planning. The IESO gets better electricity system certainty, and Ontario’s largest users get the actionable clarity they’ve been asking for.

For greenhouses and industrial loads, this is a powerful tool. It means you can match your operational needs – lighting, processing, drying, HVAC, irrigation, refrigeration – to the most cost-effective hours, without compromising output.

In short: transparency has arrived in a market that used to be largely guesswork.

What Leading Ontario Businesses Are Doing Already

Working with greenhouse operators and industrial energy teams across the province, we’re seeing impressive creativity in how businesses are using DAM insights to protect budgets and support growth.

Greenhouses are shifting lighting schedules into cheaper hours, without sacrificing plant health or yield. Factories are tweaking shift changes by 30–60 minutes. Cold storage operators are pre-cooling during low-cost hours to offset spikes later in the day. Even small hourly adjustments are creating next-month bill reductions that are impossible to ignore.

These aren’t theoretical savings – they’re material.

And in 2025’s extreme pricing environment, the stakes are high:

• Before DAM, hourly prices hit 148¢/kWh earlier this year.
  A 4MW greenhouse or industrial site would have paid $5,920 for that one hour alone.
• Since DAM launched, we’ve still seen prices exceed 35¢/kWh over the summer, with historically “cheap” overnight hours reaching 28¢/kWh—compared to the usual 3–4¢/kWh average.
• Since 1st May 2025, high prices generally fall between 4pm to 8pm, and the lowest prices are typically between 12am to 6am – BUT  approx. 15% of the time the highest and lowest prices are outside of these standard ranges, and the change can be significant
• Those are the hours that catch businesses off guard. Without advance visibility, you simply miss them – and miss the savings (or avoidable cost spikes) that go with them.

When a few hours can make or break a budget line, being caught off guard simply isn’t an option anymore.

Electricity Savings That Fund Growth

With operating costs rising and capital investments harder to justify, DAM participation is becoming a strategic advantage for high-load businesses.

Here’s what tapping into Day Ahead insights unlocks:

• Daily alerts when tomorrow’s price crosses a customer-defined threshold 
• Hourly visibility into the cost of running high-load equipment
• Opportunities to shift or avoid lighting, or energy intensive processing into cheaper hours
• Real savings that free up capital for expansions, automation, robotics, and further yield-boosting upgrades

Not every business can adjust on demand – and that’s okay. Even partial flexibility makes a measurable difference.

At the very least, being informed puts you back in control.

The Full Energy Strategy Ontario Businesses Need Right Now

DAM insights are one piece of the puzzle. When layered with Global Adjustment (GA) savings through the ICI program and Demand Response earnings getting paid to support the grid, Ontario businesses can materially reduce their electricity costs, stabilize budgets, and reinvest those dollars into growth.

In an unpredictable economic and political climate, this kind of resilience matters.

Now is the moment for every greenhouse and industrial facility to review how they manage both sides of the electricity bill – and ensure they’re getting paid for every kilowatt of flexibility they bring to the system.

2025 Summer Peak Season Results

The 2025 summer was a challenging peak season in Ontario – demand levels were the highest in over a decade and there were data issues from the IESO at times, however, EnPowered hit all 5 top peaks for the Industrial Conservation Initiative (ICI).

EnPowered made 15 calls and hit all 5 peaks. In comparison, the broader market saw as many as 28 curtailments, with many capturing only 4 of the 5 peaks. 

Let’s talk about a few key facts about this summer season:

• Demand this summer was extremely higher than previous years, in fact last years #1 peak would have ranked as #8 this year!
• The heat – multiple, intense heatwaves. This summer we had 23 days over 30 degrees or higher (as compared to 14 days above 30 degrees in previous years) 
• Operating in a new market with the IESO Market Renewal Program (MRP) going live on May 1st.
• Numerous data outages or delays occurred during peak times and inconsistencies in high demand spikes and drops – we know the IESO are working through these issues.

This summer we made more calls than in any previous year, however the market dynamics drove this need as we continued to focus on our highest priority – hitting all the peaks (again). 

Looking ahead, there still remains a chance of winter peaks, but a winter demand level exceeding 24,211MW, the current 5th peak, would likely require a lengthy extreme cold snap. 

2025 Hourly Electricity Prices post Market Renewal Program

Energy prices were low in May and most of June but then rose significantly in the latter part of June through to mid-August this summer. Our Day-Ahead Price Monitoring (DAPM) service proved extremely valuable to help our customers avoid the high price hours – some got over $300MW/hour, enabling them to achieve significant savings. Now that we are into fall prices have moderated again but we still have seen days of hourly pricing crossing over $140MW/hour, still proving valuable to participate in the day ahead market to unlock savings. 

2025 Summer Demand Response Performance

This summer Ontario experienced the highest number of DR activations on record, with most activation days aligned with peak days. This meant that by participating in both ICI Peaks and Demand Response, participants were maximizing their energy savings and revenues, earning as much as $22,500/MW more by curtailing during these emergency events simply by doing what they would have done on a regular peak day anyway.

Additionally, our customers delivered their strongest performance on capacity test days, a credit to our partnering with our customers to ensure effective curtailment planning and EnPowered providing an industry leading 21 days notice of the date and time of the summer tests. 

PJM

PJM experienced record-breaking demand this summer. The top peak 160,464 MW during the June heatwave — set a new all-time high. The current top 5 peaks are split between two major heat events in June and July.

Notably we saw:

• More market participation (load reductions) is evident this year, a positive sign as capacity prices are set to rise by 25% next year so this means more customers are participating than ever before.
• Transmission zones such as PPL, Penelec, and APS have largely avoided curtailment this summer due to high winter demand setting their capacity obligations early.

Our PJM customers in ATSI, AEP, APS, METED, PSEG, and PPL zones all hit 5/5 peaks! Seeing savings up to $278,789 per MW/year in zones such as PSEG. With capacity prices set to rise in the 2026/27 year our customers benefited by additional savings this year capturing transmission peaks. In some markets responding to transmission peaks are more lucrative in savings than capacity. If you can stack these together that is even better. 

NYISO

While the official peak window in New York runs from July 1 to August 31, the first major heat wave came in June setting the highest usage values on June 23 with near-record demand levels. Nevertheless, since June doesn’t count in New York, the current #1 peak occurred on July 29 at 6-7pm, which also saw demand levels not seen in many years. 

Our New York customers received only two peak calls, including successfully hitting the July 29th peak hour for the season, helping them to reduce their iCAP tags for next year. 

What a summer so far — and there’s still more to come. Here’s a quick look at how the peak season is shaping up across the regions where EnPowered supports Commercial and Industrial (C&I) customers in lowering their capacity costs, transmission costs, and (in Ontario) Global Adjustment costs..

Ontario (IESO)

This has been an unprecedented year in the Ontario ICI peak season due to extremely high temperatures and the Market Renewal Program that occurred on the 1st May 2024. 

The first half of the season has been intense:

• 20+ days at or above 30°C since June.
• Demand peaked at nearly 25,000 MW on June 24
• This year’s current #5 peak surpasses the #1 peak in most prior years
• Unprecedented volatility in real-time demand, with swings of ±1,000 MW in only five-minutes, gaps in real time data, and delays in data reporting from the system operator. The cause of these anomalies is still unclear. 

With the likelihood of another heatwave in late August or early September, the season is far from over – and then we see what winter will bring. Our goal remains clear — capture all five peaks, maximizing Global Adjustment savings for our customers.

PJM

PJM is experiencing record-breaking demand this summer. The top peak so far — 160,464 MW during the June heatwave — set a new all-time high. The current top 5 peaks are split between two major heat events in June and July.

Notably:

• More market participation (load reductions) is evident this year, a positive sign as capacity prices are set to rise by 25% next year so this means more customers are participating than ever before.
• Transmission zones such as PPL, Penelec, and APS have largely avoided curtailment this summer due to high winter demand setting their peak obligations early.

With six weeks left in the peak season, another major heatwave could easily shuffle the leaderboard.

New York (NYISO)

While the official peak season in New York runs from July 1 to August 31, the first major heat wave came in June setting the highest usage values on June 23 with near-record demand levels. Nevertheless, since June doesn’t count in New York, the current #1 peak occurred on July 29, which also saw demand levels not seen in many years.

For our NY customers, this season has had relatively few curtailment events — but the final weeks could still bring surprises.

What This Means for Your Business

Across all markets, peak season performance is more critical than ever. For Ontario, IESO’s data challenges highlight the importance of high quality peak predictions to navigate through recent changes. In PJM and NYISO, rising capacity costs and shifting peak patterns mean proactive strategies can deliver substantial savings.

If your business isn’t currently participating in a demand management program — or if you’re unsure whether you’re capturing all available savings — now is the time to explore your options. The peaks are still coming, and every MW counts.

On May 1st, 2025, the IESO introduced a major shift to Ontario’s electricity landscape: the Market Renewal Program and the launch of a Day Ahead Market (DAM). This wasn’t just a behind-the-scenes technical update—it fundamentally changed how electricity is scheduled and priced across the province.

And if you’re a commercial, industrial, or institutional energy user in Ontario, this change means real, tangible opportunities to take control of your electricity costs like never before.

What Is the Day Ahead Market?

The Day Ahead Market strengthens Ontario’s existing market by committing most supply a day in advance, rather than in real-time. This gives the system operator (and all of us) greater confidence that electricity will be there when it’s needed.

But the real win? Visibility and predictability.

Now, large energy consumers can see hour-by-hour electricity prices for tomorrow—today. That means you can plan operations, shift load, or make strategic decisions based on how expensive (or inexpensive) electricity is expected to be.

So, What’s Actually Happening With Prices?

At EnPowered, we’ve been tracking DAM prices vs.the final Ontario Prices. The Ontario Price is the final price paid by consumers which replaces the old Hourly Ontario Energy Price (HOEP). It combines the day ahead price with a small adjustment to account for deviations from forecasts.Here’s what we’re seeing:

• Strong alignment: Day-ahead prices are typically within $3/MWh of real-time prices—less than a 10% variance in most cases.

• Exceptions? Spikes. The biggest deltas appear during major demand surges, like June 24th (3–9pm)—so far, the top peak demand day of the season.

We’re also noticing clear price shifts across the 24-hour day:

• Higher evening prices: What used to average $40–$50/MWh pre-market renewal is now trending at $70+/MWh.

• Lower overnight rates: Early-morning hours have become more affordable thanks to increased pricing accuracy and planning flexibility.

What This Means for Your Business

Let’s break it down:

On June 24th at 3pm, electricity cost $287.15/MWh. Thanks to DAM, customers knew the day before that the price was expected to be $207.94/MWh—perhaps not as high as the ultimate combined final price was, but a strong and actionable warning.

Now imagine you run a facility with a 2MW peak load:

• If you didn’t adjust, that hour cost you $574.30.

• Two days later, same hour, price dropped to $68.69/MWh—costing just $137.38!

That’s a 76% savings opportunity in electricity in just one hour —this is available for all commercial and industrial customers paying the Ontario Price.

The market has changed. The opportunity to save is real and immediate.

From Global Adjustment to Energy Charges—Let’s Tackle It All

For the past decade, EnPowered has helped businesses across Ontario reduce Global Adjustment costs, one of the largest line items on any industrial electricity bill.

Now, with the Day Ahead Market in full swing, we’re going after the next big line item: energy charges.

You no longer have to guess when prices will spike. You don’t need to react blindly. You can plan and act with confidence.

Try It For Yourself—Free

We’re offering a 21-day free trial of our Day Ahead Price Alerts. No guesswork. Just daily updates with tomorrow’s prices—hour by hour—so you can make informed decisions that lower your costs.

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The Ontario energy market has changed. It’s time your energy strategy changed with it.

At EnPowered, we’ve been tracking these changes closely. More importantly, we’re already helping our customers turn this challenge into an opportunity. With the introduction of a new Day-Ahead Pricing Alerts, we’re providing timely intelligence so customers can avoid high-cost hours and reduce their electricity bills — with confidence and clarity.

So what is the Market Renewal Program, and what does it mean for your business?

The MRP introduces two major structural changes:

First, it replaces the old two-schedule system (where one schedule determined which energy resources would run, and another calculated prices) with a streamlined single-schedule market. This simplifies market operation and ensures that pricing reflects  system needs more accurately.

Second, and most importantly for businesses, the MRP introduces a Day-Ahead Market (DAM). This means that most electricity pricing and schedules will be determined a day in advance — giving  consumers a preview of the next day’s market conditions.

Together, these reforms will bring more efficiency to the Ontario market as well as actionable transparency – flexible loads can take advantage of pricing information to avoid high priced hours as well as fully leverage lower priced hours.

Before we go deeper into how to capitalize on this, let’s clear up one common concern: the MRP does not affect the Industrial Conservation Initiative (ICI).

This is important. Many businesses have reached out to us asking if ICI and the Coincident Peak (CP) program will change after May 1. The answer is no. While the markets which set the prices of electricity will have changes, the Global Adjustment (GA) costs to be recovered through the ICI program will remain unchanged — which EnPowered supports with daily peak alerts and strategy guidance. So, if you’re participating in ICI, nothing changes.

But your commodity costs — the hourly price of electricity — will change. That’s the part MRP transforms, and that’s where savings are possible.

Here’s how.

Electricity prices will continue to vary hour to hour. During peak demand — think hot summer afternoons — prices may spike. During off-peak times — overnight, weekends, or mild weather — prices may drop significantly. The greater the price spread, the more opportunity there is to manage your usage smartly and cut costs.

And with the new Day-Ahead Market, you’ll know when those expensive hours are coming before they hit. That’s a game-changer.

EnPowered’s new Day-Ahead Pricing Alerts helps customers unlock this advantage. We take DAM prices, analyze them, and provide you with customized, clear, actionable insights on tomorrow’s energy pricing. We’ll highlight which hours will be most expensive, and how you can adjust your operations to reduce your bill.

For example, take a greenhouse in Southern Ontario. During the winter months, its supplemental lighting system runs 18 hours a day, drawing several megawatts of power to support crop growth. Under the old system, the greenhouse might not know until the next day that they were running lights during a price spike.

But under MRP, with EnPowered’s help, they’ll know that tomorrow between 4 PM and 7 PM, prices are expected to surge to $290/MWh. By shifting lighting to earlier or later in the day — or dimming output slightly during that window — the greenhouse can avoid high prices without impacting plant health. The result? Thousands of dollars saved over the course of a season.

This is just one example. Similar opportunities exist for manufacturers, cold storage facilities, data centers — any operation with flexibility in their electricity use.

And that’s the heart of the message: with better information comes better control.

EnPowered is already a leader in helping Ontario businesses manage electricity risk. Our North American CP and DR programs save customers millions annually. With the launch of our Day-Ahead Pricing Alerts, we’re extending that expertise into a new frontier — helping you get ahead of commodity pricing and act in advance, not in hindsight.

The MRP may be new to Ontario, but guiding customers to minimize their net electricity costs is familiar territory for us.

And while no one can predict exactly how the market will behave after May 1, we’re confident that flexibility, insight, and proactive decision-making will be the keys to success.

We’re here to make that easy for you.

If you’d like to sign up for our Day-Ahead alerts and gain notifications covering tomorrow’s price intelligence, reach out to chat with our team. We’ll walk you through how the alerts work, what kind of savings to expect, and how to integrate it into your existing operations with zero disruption.

The Ontario market is evolving. Make sure your energy strategy evolves with it.