Twenty-two years after it went live, Ontario’s independent electric system operator, IESO, has launched its Market Renewal Program (MRP), instituting a nodal day-ahead market that covers more than 900 locations. 

The revision appears to have gone smoothly, with the grid operator now joining the seven U.S. ISOs and RTOs that have day-ahead structures. Given that fact, it’s an opportune time to look at the bigger picture of Ontario’s structure and competitive electricity markets in general. 

DA markets typically are where the largest volumes of electricity are transacted on a location-specific nodal basis, with varying levels of nodal granularity. Under its earlier approach, IESO had operated only a real-time market with a single price, irrespective of location or transmission constraints. 

Generators could schedule their output the day prior, but commitments were not financially binding. Any inefficiencies or price discrepancies, including congestion, were settled through compensatory out-of-market payments, and discrepancies between expected generation and actual real time operations were not subject to penalty.  

Under the new MRP, day-ahead market offers — which create financial obligations to deliver energy the following day — will be scheduled to match forecast demands. Prices will be bound by a floor of -$100/MWh and a ceiling of $2,000/MWh.  

In some ways, it’s surprising the move took so long. Locational day-ahead markets create more market efficiency while also offering grid operators and market participants better foresight into what will happen the following day. They are more deliberately proactive and less reactive to real-time events.  

The move was a big step for IESO and one of the biggest tweaks to its market design in years. And while it increases the overlap in the Venn diagram with other market operators, IESO’s action and market redesign highlights a very curious fact about North America’s restructured markets: Each “deregulated” market embraces the overriding concept of competition but then spikes the drink with its own highly local flavors. 

Editorial pet peeve: It’s not clear why people insist on calling this “deregulation.” With highly complex competitive markets superimposed on regulatory supervision for distribution at the state or provincial level, there are far more — and more complex — rules than ever existed before the advent of competition. And operators keep tweaking them to respond to the latest perceived market shortcoming. 

These market flavors also defy any attempt by generators, battery operators or demand response aggregators to achieve economies of scale — no, we have created a true Tower of Babel here.  

To illustrate the nature of this multifaceted hydra, let’s take the issue of capacity in a number of markets. Texas has no capacity market, letting energy scarcity prices offer the signals, although operating reserves are in the mix as well. Meanwhile, ISO-NE and PJM hold formal capacity market (FCM) auctions three years in advance — unless the regulatory conversation gets so muddled that they get delayed for years, as has been the case for PJM. 

New York long ago decided the FCM approach was too potentially inefficient and risky, and opted for monthly options with the possibility of transacting seasonal strips. Meanwhile, on the West Coast, California’s ISO tasks the utilities with procuring capacity resources. 

In many markets, capacity represents a noticeable element on the wholesale power bill. Exhibit A is PJM, with its recent eye-watering 2025/26 auction results at just under $270/MW-day, and the just-formalized floor and ceiling prices of $175 to $325/MW-day for the coming two auctions. Exhibit B is MISO’s just released auction results for this summer, coming in devilishly high at just over $666/MW-day and annually between $212 and $217/MW-day. They make PJM look tame by comparison.  

But nobody does capacity quite like Ontario, and that hasn’t changed with its Market Renewal.  

Capacity and the Global Adjustment Charge (GAC)

As in other markets with capacity prices, the GAC — established in 2006 — is intended to cover the cost of building and maintaining supply infrastructure to ensure system resource adequacy. The initial MRP proposal intended to do away with the GAC and replace it with a formal capacity auction. However, pushback from various stakeholders resulted in this plan being abandoned.  

Unlike the role of capacity pricing in other markets, though, the GAC specifically addresses the difference between the total compensation made to certain contracted generators and any offsetting market revenues. As such, there typically has been a strong inverse relationship between wholesale electric energy prices and the GAC. When wholesale energy prices are lower, the GAC is higher, and vice versa. And energy prices historically have been very low, with the result that the GAC typically is the largest single element on the average consumer’s total wholesale power bill, often representing up to 65% or more of the monthly costs.  

Ontario’s GAC will continue under the new program, but its impact and interaction will change slightly. The greatest impact may simply be that it will reflect greater location-specific volatility resulting from a nodal pricing program that specifically integrates the impact of congestion. 

Lower hourly energy prices will result in higher compensatory GACs, and higher prices will result in the opposite. Only time will tell whether capacity costs will decline as a total percentage of the entire wholesale bill. But if the history of many other grid operators is any guide, the rules-tweaking is far from over. Call it whatever you want, but don’t call it “deregulated.” 

Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter.