A 78 €/MWh Swing in Four Years: Europe's Power Market Is Splitting in Two

Four years ago, Germany was the cheap one. In 2022, French wholesale power traded 40 €/MWh above Germany. Today France sits 38 €/MWh below it. That is a 78 €/MWh swing on a single spread in four years — and almost nobody is talking about it.

I have been tracking European day-ahead spot prices across the continent, and what struck me this spring is not any single country's number. It is that the prices have stopped moving together. Europe used to have one power market with local quirks. It now looks like two markets that happen to share a map.

The chart above is the FR–DE spread, year by year, on a consistent convention: positive means France is the more expensive of the two. The flip from a +40 €/MWh peak in 2022 to −38 €/MWh today is not a wiggle. Germany has been climbing for three straight years while France has held flat. And the two countries pay the same gas price and sit under the same carbon market — so this gap is not about fuel. It is structural.

Two Europes

Zoom out from the FR–DE pair and the same pattern repeats across the continent. The post-crisis years have sorted Europe's large markets into two clusters.

On one side, a low-price Iberian–French group: Spain at 47 €/MWh year-to-date, France at 59 €/MWh. On the other, a high-price DACH–Benelux cluster, with Germany, Belgium and the Netherlands all bunched between 92 and 96 €/MWh. The gap between the two groups is now roughly the price of the electricity itself — one cluster pays double the other.

Greece is the interesting third case. Historically it sat above the European average every single year. In 2026 it has converged into the pack, at 93 €/MWh against an EU mean of 91 — within a rounding error of the continent for the first time in the series. Greece is doing now, by the bottom, what Iberia did about two years earlier.

Yearly average day-ahead price (€/MWh)

Year	Greece	Spain	France	Germany	Belgium	Netherlands	EU
2018	60	57	50	53	55	53	53
2019	64	48	39	38	39	41	45
2020	45	34	32	30	32	32	34
2021	116	112	109	97	104	103	108
2022	280	168	276	236	245	242	245
2023	119	87	97	94	97	96	100
2024	101	63	58	79	70	77	79
2025	103	65	61	89	82	87	89
2026 YTD	93	47	59	96	92	96	91

ENTSO-E day-ahead spot, year-to-date as of 18 June 2026.

Four countries, four trajectories

Spain — the showcase

Spain is where the bifurcation is most visible. At 47 €/MWh year-to-date, down from 65 last year, it is the cheapest large market in Europe by a wide margin. Behind that number is an aggressive solar build-out that has crossed a threshold: renewables now set the price for a majority of hours, and the gas signal barely transmits anymore. An electro-intensive plant making a siting decision today would see Spain at less than half of Germany's wholesale cost.

Greece — convergence by the bottom

Greece spent a decade as one of the most expensive markets on the continent, structurally above the EU average. The 2023–2025 solar wave has pulled it down into the pack. It is worth watching precisely because it is following the Iberian script with a two-year lag — the same cause, the same trajectory, just earlier in the curve.

France — the steady reference

France is almost boring, and that is the point. At 59 €/MWh it is in line with 2024 and 2025, quietly remaining one of the cheapest large markets in Europe year after year. No drama, no spike, no climb.

Germany — the warning sign

Germany is the one that should give people pause. It has climbed three years running — 79, then 89, now 96 €/MWh — and for the first time in the series it sits above the EU average. This is the highest German average since the gas-crisis peak of 2022, and the gap to France is still widening.

The usual reassurance is that more renewables will fix this. The data does not yet support that. Despite continued solar additions, Germany's count of hours below 1 €/MWh is actually regressing in 2026, projecting lower than last year. The renewable-surplus story everyone associates with the energy transition is happening in Spain and France — not in Germany. There, gas plus carbon still sets the marginal price too often for the average to come down. Belgium and the Netherlands sit in exactly the same regime, captured by the same market coupling and the same gas-set margin.

The surplus is happening elsewhere

One way to see this divergence is to count the hours when power is effectively free — below 1 €/MWh, the level at which storage can charge at negligible cost. (I use below 1 €/MWh rather than below zero because mandatory curtailment increasingly suppresses the strictly-negative count, masking the true surplus.) Project the current year-to-date pace forward and the split is stark:

Share of hours below 1 €/MWh

Country	2025	2026 (projected)
Spain	12%	~20% — roughly one hour in five
Greece	5.6%	~14%
France	10%	~14%
Germany	8.6%	~8% (flat)
Belgium	7.6%	~7%
Netherlands	8.4%	~7%

Linear projection from year-to-date pace. Greece has already passed its full-year 2025 count of sub-1 €/MWh hours with more than half of 2026 still ahead.

The low-price cluster is filling up with free hours; the high-price cluster is, if anything, going backwards. Spain is on track to deliver roughly one hour in five below 1 €/MWh this year. Germany, despite adding capacity, is flat. Whatever is compressing prices in Iberia is not reaching the DACH region.

The policy gap

This is where I think the story stops being a market curiosity and becomes an industrial one. Put yourself in the seat of someone deciding where to build an electric-arc steel mill, an aluminium smelter, a chlor-alkali plant or a hyperscale data centre. That decision commits capital for ten to twenty years. The number that matters to them is the expected weighted-average wholesale electricity cost over that horizon. Not installed capacity in gigawatts. Not renewable share in percent. A price.

And here the national frameworks have quietly diverged. Spain pairs its solar build-out with contract-for-difference auctions that publish explicit strike prices. France anchors its historic fleet around an explicit price target. Several countries are embedding long-term industrial contracts at a known €/MWh. In each case, an industrialist can read a number off the policy and plan against it.

Germany's framework is built almost entirely around installed-capacity targets — gigawatts of solar, wind, batteries, electrolysers — and renewable-share percentages. There is no published "delivered wholesale €/MWh" objective for industry. The levy reform moved the cost question into the federal budget and, with it, moved the conversation further away from any explicit price commitment. An industrialist cannot sign a fifteen-year capex decision against a renewable-share target. They need a price target. Iberia has given them one. Germany has not.

I can anticipate the objections, because I have heard them.

"Germany's high price is just gas and carbon pass-through — it's cyclical." Partly true on the absolute level. But the FR–DE spread cannot be explained that way: the two countries pay the same gas and sit under the same carbon market. The 38 €/MWh gap is about how much renewable penetration has decoupled the average from the gas-set margin. Iberia has crossed that threshold; Germany has not.

"Germany has invested massively in renewables — this can't be a policy failure." Two things argue otherwise. Its sub-1 €/MWh count is regressing in 2026, which is not what continued solar additions would produce if the build-out were structurally working. And onshore wind — the technology that matters for the non-midday hours — has been roughly stagnant for four years.

"More flexibility — batteries, demand response — will normalise German prices." This one is more subtle, and I think it has the causality backwards. Battery business cases need a wide spread between peak and trough to amortise. Germany's distribution is narrow: anchored at the top by gas, rarely going deeply negative at the bottom. A compressed spread starves new flexibility of returns. The narrow distribution is not a problem flexibility will solve so much as a condition that discourages flexibility from being built.

The part nobody wants to say out loud

I deliberately kept nuclear out of the framing above, because it tends to swallow every energy conversation it touches. But a serious look at this divergence cannot leave it unsaid. France's structural cheapness owes a great deal to its nuclear fleet — low-carbon, low-marginal-cost baseload that holds the average down.

What makes the German position uncomfortable is the comparison that follows. Spain delivers low wholesale prices through a near-complete renewable model. France delivers low wholesale prices through a nuclear model. Two opposite routes, both arriving at a competitive industrial power cost. Germany's case is harder precisely because it is neither — and the result is the highest large-market price on the continent.

Is this the precursor of something bigger?

The German industrial machine has been the engine of Europe for decades. None of this is destiny — capacity can be built, frameworks can be rewritten, the spread can close. But the direction of travel has been consistent for three years now, it is visible in the spread, in the country averages and in the free-hour counts at the same time, and it tracks a real difference in how countries write their energy policy.

So the question I keep coming back to is not whether German power is expensive this year. It is whether what we are watching is the early signature of a profound transformation of German industry — and whether the policy gap that helped open this divergence is the thing that keeps it open.

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