Nordic power supply tightens as hydro deficit and nuclear uncertainty squeeze Q3 outlook
A 26 TWh hydro shortfall and unmet nuclear expectations are pushing Nord Pool spot prices above early-July forecasts of EUR 50/MWh.
Nordic hydropower reserves sat 26 TWh below normal as of mid-May, and Montel EQ's weather models pointed to continued dry conditions over the following two weeks — offering no near-term prospect of replenishment. With that buffer still depleted, the supply assumptions underpinning the most recent Q3 price forecasts look increasingly thin.2
Analysts told Montel in early July (week of 2026-06-29) that Nordic spot power would average around EUR 50/MWh in Q3, down 26% from EUR 68/MWh in Q2, on the expectation that demand would ease and nuclear output would recover after spring maintenance. Both assumptions have since come under pressure.3
The nuclear recovery those forecasts depended on has been uneven. Fortum on Thursday (2026-08-27) submitted a state aid application to open talks with the Swedish government on the terms for a new nuclear project, with a proposed scope of 1,200 MW to 3,400 MW depending on technology choice and demand growth. The application signals long-term ambition, but it does nothing for available capacity this quarter or next.4
Sweden has spent recent years shifting its electricity policy from a 100% renewable target to a 100% fossil-free framework, precisely to allow new reactor construction. That political adjustment created the legal space for Fortum's application, but construction timelines for new nuclear in Europe have a poor record of shortening once talks begin. The existing fleet carries the supply burden in the interim, and any unplanned outage tightens a market that is already short on hydro.4
The case for a softer Q3 was partly built on the expectation that European renewable generation growth would spur imports into the Nordic region, limiting the damage from the hydro shortfall. Analysts made that argument to Montel in May (2026-05-21), noting that the expansion of green output across the continent had made Nordic and European power systems more resilient than they were during the 2022 energy crisis.2,1
That cushion has limits. Resilience to gas supply shocks is not the same as surplus generation capacity. When continental prices are firm, Nordic buyers drawing power through interconnectors absorb the hydro deficit through import costs rather than escaping it. The import-offset argument holds most cleanly when continental generation is ample and cheap; the current environment is neither.1
On the demand side, a wave of hyperscale data centres across the Nordic region is running into grid access constraints. Analysts said in late August (week of 2026-08-24) that limited grid capacity was forcing politicians to prioritise which projects connect first. In the near term this acts as a brake on load growth, but the pipeline of approved connections points to substantial demand increases once the grid bottleneck eases. The Q3 spot forecasts from early July do not appear to have fully weighted that structural shift.5
The result is a Q3 supply picture tighter than the EUR 50/MWh consensus implied. Hydro is short. Nuclear output has not rebounded as cleanly as expected. Import relief from continental Europe has limits. And data centre load is a variable the early forecasts underweighted on both sides — constrained now, but a rising floor once connections are approved.3,25
The next test comes from the weekly hydrological data. If Nordic reservoir inflows stay below normal through September, the 26 TWh deficit carries into the winter draw season, when demand rises and the continental generation surplus that supports Nordic imports tends to shrink as other European markets face their own peak loads. Spot forecasts built on a soft-demand, recovering-nuclear, import-cushion view of Q3 were never designed to hold under all three assumptions weakening simultaneously.2