Why Ontario’s Global Adjustment Went Negative This Winter, and Why That Doesn’t Mean Your Electricity Got Cheaper

Ontario electricity bills for January and February 2026 contained a line item that generated pointed questions from a lot of energy managers: a negative Global Adjustment rate. For facilities that have spent years trying to reduce GA exposure, a credit on that line looked like good news. For most, it was not.

Understanding why requires a short look at how the GA actually works, what drove the winter spike, and what the forward outlook means for Class A facilities making decisions right now.

How the GA residual works

The Global Adjustment is calculated monthly as the difference between the total cost of Ontario’s regulated and contracted generation, primarily OPG’s nuclear and hydro fleet and the IESO-administered legacy gas contracts, and the revenue those generators collect from the wholesale market. When wholesale prices are low, generators fall short of their contracted revenue and the GA makes up the gap. Ratepayers pay it.

The inverse is also true. When wholesale prices run high enough, generators earn above their contracted minimums. The residual flips negative, and ratepayers receive a credit.

According to Power Advisory analysis, the approximate tipping point sits between $90/MWh and $105/MWh on the day-ahead Ontario Zonal Price, though historically that threshold would have been closer to $115/MWh to $130/MWh without the government’s Comprehensive Electricity Plan offsetting a portion of GA costs.¹ Ontario rarely sustains prices above the current breakeven for more than a few hours at a time. This past December and January, it did.

What drove prices that high

Power Advisory’s analysis points to two concurrent forces: supply tightness and market design transition. Roughly one-third of the price spike was attributable to tight supply conditions, outages, and system constraints. The other two-thirds reflected the structural effects of Ontario’s Market Renewal Program, which rolled out all of its changes simultaneously.²

The MRP transition introduced locational marginal pricing, changed ramp rate pricing from a 12-times to a 1-times multiplier, which reduced the buffer that previously smoothed short-term price swings, and replaced control area operating reserve with a standalone operating reserve price. Those changes, taken together, produced significantly higher day-ahead and real-time price volatility. Power Advisory notes this is an expected consequence of changing market states all at once.²

The winter conditions amplified both factors. Ontario and neighboring markets experienced simultaneous supply tightness. Natural gas at Dawn cleared above $90/MMBtu on at least one day during the period, an extreme reading driven by competing demand from New England, New York, PJM, and Atlantic Canada. Under the renewed market design, exports can now set the day-ahead price, a change from the legacy market where exports were price-takers. With neighboring markets short on supply and willing to pay a premium, export demand pushed the Ontario Zonal Price higher, reducing the net GA obligation.²

The credit did not offset the bill

Here is where facilities that read only the GA line got surprised. Day-ahead energy prices that typically run 4 to 5 cents per kilowatt-hour reached approximately 13 cents per kilowatt-hour during the spike months. As a directly observed example, a facility with $70,000 in monthly energy charges received a GA credit of roughly $12,000, leaving a net bill still approximately $10,000 above a normal month.²

GA is applied provincially. LMPs are locationally set. Facilities in higher-priced zones received the same provincial GA credit as facilities in lower-priced zones, but paid materially more on the energy side. The credit did not scale with local exposure. For large industrials in congested zones, the mismatch was significant.²

The energy component moved far faster than the GA credit could recover. Negative GA helped at the margin. It did not make January cheap.

The outlook

Power Advisory still expects GA to be positive on an annual basis, even in years with periodic negative months. The current volatility is expected to ease as market participants adjust to the renewed market design and as roughly 3,000 MW of large energy storage comes online in Ontario, providing active rebalancing capacity on both the supply and demand side.²

The long-term trajectory is upward. OPG’s regulated hydro and nuclear rates are projected to reach $200 to $215/MWh by 2030. Power Advisory indicates this rate path will push long-term GA approximately 10 percent higher than previously forecast. New procurements entering the GA cost pool will not materially offset the OPG rate increase. That is the dominant driver.²

Periods of negative GA will recur during peak seasons until Ontario’s supply position tightens further, with Pickering’s remaining unit retirements expected to reduce firm capacity before the next wave of refurbished nuclear and storage resources fully offsets the gap. On an annual basis, GA is not declining.²

What this means for Class A facilities

The Class A incentive structure is unchanged. A facility’s share of the GA cost pool is still set by its consumption during Ontario’s top five system peak hours. As OPG’s regulated rates increase through the decade, the dollar value of favorable peak performance compounds year over year.

As of March 2026, large industrials are responding to this environment by becoming more active as dispatchable loads or Price Responsive Load participants, locking day-ahead consumption to avoid real-time price spikes. Both moves reduce exposure to the locational price spikes that GA credits cannot fully offset. Facilities that deferred those decisions based on a negative GA reading this winter are now behind.²

The months that determine your Class A allocation for the 2026-27 capacity year are being set now. Your performance during Ontario’s top five peak hours will affect your GA allocation for the full year ahead, at rates that are going up, not down. If your facility has not modeled its current peak exposure under the renewed market’s locational pricing structure, run that analysis now.

Part 2 of this analysis, Negative GA Was Not Relief. It Was a Signal., takes up the strategic question this winter raised: whether the energy strategy most Class A facilities are running can still reach the exposure the market now produces.

Ready to see where your facility stands?

Rodan cleared 288 MW in the IESO 2026-27 Capacity Auction. Operating since 2003, Rodan is Ontario’s largest demand response provider, with 750+ facilities and 225+ utilities, ISOs, and power producers under management. Rodan’s market desk handles Day-Ahead Market participation for Ontario Class A and large industrial facilities.

Book a 30-minute fit assessment.

You’ll leave with the day-ahead basis modeled at your specific delivery point, your PRL revenue opportunity sized, and HDR stacking mapped against your registered Maximum Load.

rodanenergy.com/flexops-load  |  1-866-999-5006  |  info@rodanenergy.com

Notes

1. Brady Yauch (Director, Markets and Regulatory Affairs, Power Advisory LLC), February 2026.
2. Travis Lusney (Power Advisory LLC), March 2026.