What is moving the price right now?

The breakout we described at the end of August has widened into a repricing. EEX German baseload Cal-27 closed at 132.03 EUR/MWh on 11 September, up 26.1 percent on 11 August and again a high for the series. The distance to June is the real finding: the same contract then stood at 96.01 EUR/MWh. In one quarter the German forward market has gained 37.5 percent without anything changing in German generation structure.

The driver sits entirely in the gas market. The TTF front month rose 35.4 percent over the same monthly window to 79.52 EUR/MWh, because Europe is injecting into storage against the clock while Qatari LNG passes the Strait of Hormuz only partially. German storage stood at 55.60 percent on 13 September, and EU-wide at 68.04 percent (GIE AGSI). As long as gas plants set the price peaks, that tightness transfers one to one into the power forward.

What is new is that the support from the west is giving way. French Cal-27 rose from 64.71 EUR/MWh on 11 August to 89.54 EUR/MWh on 11 September. EDF extended the outage of the Gravelines 5 reactor by seven weeks to 25 January 2027 after corrosion was found (Bloomberg, 3 September); in August, following jellyfish ingress and heat-related cooling restrictions, 20.4 percent of French nuclear capacity was temporarily offline, a record. The German-French gap therefore stands at 42.49 EUR/MWh after 40.00 EUR/MWh in mid-August: it has not widened because Germany got dearer, it has widened only slightly despite France rising too. The argument for the location comparison holds, but its basis is shifting.

On the spot market autumn has already begun. The German day-ahead spot averaged 162.39 EUR/MWh over the week of 7 to 13 September. On 10 September a Dunkelflaute met the evening ramp: the daily average rose to 191.82 EUR/MWh and the quarter-hour peak between 19:45 and 20:00 reached 585.10 EUR/MWh. That is the cost structure that recurs regularly in the winter profile, and it hits any plant without load flexibility in full.

On the policy side three things run in parallel, all concerning 2027. First, grid fees: the transmission system operators publish provisional 2027 figures in early October, and the federal subsidy falls under the draft budget from 6.5 billion EUR to around 5.5 billion EUR, close to 15 percent less. Second, capacity build-out: the first tender under the power plant security act, for 4.5 GW, closed on 8 September and was significantly oversubscribed; awards are due by 3 November, with further rounds in December 2026 and May 2027. Third, security of supply: the Bundesnetzagentur has set the grid reserve requirement for winter 2026/2027 at 7,407 MW, after 6,493 MW the previous winter.

The most important relief is now precisely quantified. According to BAFA, the industrial power price scheme works with a reference price of 87.44 EUR/MWh and a target price of 50.00 EUR/MWh; the difference of 37.44 EUR/MWh is granted on 50 percent of eligible electricity consumption. Across total consumption that comes to around 18.72 EUR/MWh, or around 20.6 EUR/MWh with the 10 percent flexibility bonus. Companies in Partial List 1 of the KUEBLL annex qualify, the programme runs for delivery years 2026 to 2028, and applications for 2026 open in December 2026.

What we watch: the provisional grid fees in early October, the power plant tender awards by 3 November, French availability through the winter, and TTF as the continuing governing variable.

What does this mean for procurement in Europe?

Tranche discipline has shown its price, and it remains right nonetheless. Anyone who waited at the end of August for the triggers named then is paying 26 percent more today. That does not mean fixing everything now: buying Cal-27 at an all-time high is the same bet with the sign reversed. Hedge the share you cannot carry open in budget terms, and hold the rest against defined triggers: a TTF pullback below 65 EUR/MWh, an implemented corridor agreement, or German storage above 70 percent.

The KUEBLL check now belongs ahead of every tranche decision, and it can be calculated exactly. With a reference price of 87.44 EUR/MWh and a target price of 50.00 EUR/MWh, the differential is 37.44 EUR/MWh on half of eligible consumption, so around 18.72 EUR/MWh across total consumption and around 20.6 EUR/MWh with the flexibility bonus. Against a forward of 132.03 EUR/MWh that is roughly 14 to 16 percent of procurement cost. If you sit in Partial List 1 and are not yet prepared, assemble the application documents now: the application window for 2026 opens in December 2026.

Budget 2027 grid fees as their own line item and with an upside risk. The federal subsidy falls by close to 1 billion EUR and the provisional figures arrive in early October. If you have already built the 2027 budget, mark the position as open rather than rolling forward the 2026 value.

Keep using the France comparison, but with the new reasoning. The 42.49 EUR/MWh gap persists, yet France has itself risen by almost 25 EUR/MWh. A supplier with French production still cannot justify an energy surcharge at German levels, but it now has its own evidenced cost argument. Require proof of the actual procurement level rather than accepting flat surcharges.

Turn load flexibility into a number in the business case. 10 September showed what a Dunkelflaute costs in the evening ramp: 585.10 EUR/MWh at the peak against a weekly average of 162.39 EUR/MWh. If you can move processes out of those windows, you buy your way out of the most expensive hour, and in the winter profile that hour returns regularly.