Industry follows working hours. Households follow schedules. Heating follows weather. The result is a familiar shape: a morning ramp around 06:00, an evening peak around 19:00, a long overnight valley. Weekends sit lower because most factories are closed.

Demand is the most predictable thing on the grid; everything else has to chase it. Buildings and industry account for most of it today. Transport is still small. The next decade will pull more load into the evening as heat pumps and EVs scale.

Each day, an auction sorts power plants from cheapest to most expensive and switches on enough of them to meet the next day's demand. Solar and wind go first at zero marginal cost. Nuclear and hydro fill in. Gas and coal sit on top.

The most expensive plant the market has to switch on sets the price every other plant gets paid. That's gas most evenings; in Poland, still coal. When wind and solar flood the bottom of the stack, the marginal price drops with them.

Surplus crosses borders every hour. A windy Denmark sells into Germany; midday Iberia into France; overnight Poland buys from Czechia. Bigger price spread, bigger flow, until the wires are full.

Cheap northern Norwegian hydro can't just flow to Italy. The power has to hop through three or four zones, and every hop runs through wires that other producers are trying to use too. When one of those wires fills up, the cheap power stops moving, even when the price spread is huge.

The same friction lives inside countries. In Germany, North Sea wind can't reach Bavarian load because of delayed transmission buildout. Iberia is in effect an electrical island, with cross-border capacity at just 3% of its generation. New generators across Europe wait years in queue to connect to the grid.

Wind costs almost nothing to run once it's built: no fuel, no carbon. That puts it at the bottom of the merit order alongside solar. A windy day pulls the clearing price down across the whole system. Two fleets: 245 GW onshore across the continent, and 35 GW offshore in the North Sea. Offshore is only about 13% of installed capacity but generates closer to a quarter of total wind output, because wind at sea is faster and steadier. Both swing together on the same Atlantic pressure-system cycle of 1–3 days.

The cost of producing a megawatt-hour is the easy part. What each one earns when it does blow is the question that decides whether more get built. Every new gigawatt drives down the clearing price during windy hours. So the next gigawatt depends on whether something can absorb the surplus — storage, flexible demand, or an interconnector to different weather — or whether it gets built where the weather itself is different, like the summer-peaking Aegean or the Mediterranean Mistral.

Solar runs on a clock: peak at midday, dark at night. Clouds change the amplitude, not the timing. Over 400 GW across the EU. Germany alone runs 117 GW — more than Iberia and France combined — and every European market has been adding capacity for five years. But 2025 broke the streak: the first year-on-year decline since 2016.

Midday is now the cheapest hour in sunny markets. Demand still peaks in the evening, but solar peaks at midday. The result: noon prices crash while evening prices stay high. The question is who absorbs the surplus. Batteries that charge for the evening, factories shifting production into the cheap hours, interconnectors that ship the surplus where the sun isn't shining. All of them get more valuable as solar saturates more days. And wind helps too: its overnight and winter peaks fall in the hours solar can't fill.

Batteries are the natural counterparty to wind and solar. They charge when the grid has surplus, like windy overnights and sunny middays, and discharge when residual load is high and gas sets the price.

Cheap batteries are arriving just as the grid needs them most. Lithium-ion costs have fallen roughly 90% since 2010, with grid-scale battery packs now at ~€65/kWh (down 45% in 2025 alone). At scale, the fleet absorbs solar surplus at noon and softens the evening peak that gas would otherwise serve.

Almost none of these batteries are made in Europe. The LFP chemistry that dominates grid-scale storage is a Chinese supply chain end-to-end; Korean firms supply most of the rest. Europe's own bet — Northvolt — collapsed in March 2025. China's CATL is now building Europe's largest battery plant, in Hungary. The buildout is happening on European soil; the supply chain is not.

Hydro is currently the only large-scale storage that can balance the system. Li-ion batteries do four hours; reservoirs hold months. When wind and solar push midday prices down, hydro waits and sells into the expensive evening hours. As wind and solar grow, hydro gets more valuable.

Hydro comes in two forms. Conventional reservoirs store rainwater behind a dam and release it once through turbines: a one-way flow. Pumped storage cycles water between two reservoirs at different heights, pumping uphill when power is cheap and releasing downhill when it's expensive, recharging like a battery. Pumped storage is where growth is happening. Europe has almost no suitable rivers left for new conventional dams.

Norway holds around 87 TWh of stored water — roughly half the continent's — and HVDC cables link it to the European grid. That makes Norway Europe's effective battery. The risk is drought: in 2022 it slashed Italian and Spanish output, and operators now watch Norwegian reservoir levels as an early-warning signal.

Gas plants fire up when nothing cheaper can serve the load — typically the evening, when solar fades and demand rises. The Netherlands, Italy, the UK, and Germany run gas as a meaningful share of evening supply. France keeps it as a small block behind the nuclear floor. The Nordics barely use it; hydro covers their flexibility instead.

Before 2022, most of Europe's gas came through Russian pipelines at captive prices. Since the invasion of Ukraine, the continent has shifted to LNG shipped from the US, Qatar, and Norway. European gas now trades against the global LNG market. The 2026 Strait of Hormuz blockade is the live example: about 10% of European LNG passes through the strait from Qatar, and European gas prices have roughly doubled since Iran closed shipping in February. Smaller shocks — like a cold snap in Texas — feed through within days too.

Gas is no longer the volume-mover it was twenty years ago. Renewables and nuclear carry more megawatt-hours, and cheap renewable hours push gas plants out of the merit order more often — many now lean on capacity payments to cover fixed costs. But gas still sets the marginal price in most evening hours, which means every other plant in the auction is now indirectly exposed to global LNG prices.

Nuclear plants generate steady electricity from controlled fission, running for months at a time before refuelling. Nuclear's value is its ability to run continuously.

The current fleet is mostly legacy, built between the 1970s and 1990s. France runs around 45 GW continuously, hour after hour, more than the rest of Europe combined. Germany completed its phaseout in April 2023, after gradually closing reactors since Fukushima in 2011. At peak the fleet ran ~22 GW — close to 40% of Germany's average demand today. Italy and Sweden also closed reactors. The engineering expertise that built and operated all of this aged out with the fleet.

Nuclear is having a renaissance. Poland, the Netherlands, Czechia, Slovakia, the UK, and France are planning new builds, motivated by energy security. But the economics are tough: renewables crash midday and windy-hour prices, and new builds take decades and cost tens of billions of euros. Operators lean on government financial support to make the economics work. For France and the UK there's an extra motivation: civil nuclear shares supply chains and expertise with their nuclear weapons programmes.

Coal still anchors the evening stack in a handful of countries. Poland runs the largest fleet, and it remains the dominant fuel of the Polish grid. Germany carries a shrinking lignite block. Czechia, Bulgaria, and Romania hold smaller positions. The UK closed its last plant in September 2024. Western Europe is essentially out.

Coal used to be everywhere on the continent. It isn't now. Renewables crashed its capacity factor; carbon pricing crashed its margin. Where it still runs, marginal price tracks ETS carbon directly. Germany's exit is set in statute for 2038, with a review scheduled for 2030.

Coal's supply chain splits in two. Lignite is mined and burned locally — too low-energy-density to ship economically. Hard coal is mostly imported; Russia was the largest source until the EU banned Russian coal in August 2022, with the trade reshuffled to South Africa, Colombia, Australia, the USA, and Indonesia. EU coal generation briefly rose in 2022 — gas prices were even higher, and some countries reactivated retired plants. Poland's transition pace is one of the biggest open questions in European power: coal anchors ~60% of generation, the coal industry sustains hundreds of thousands of jobs, and replacement capacity is years away.

Every hour of generation across this week has a price tag, set the night before in an auction. Each country clears 24 hourly prices for the next day — what generators get paid, and the wholesale floor under every consumer bill.

Different fuels, different weather, different grids in every country would naturally pull each price its own way. The auction mechanism fights that: when there's spare cable between countries, surplus flows where it's needed and neighbouring markets clear at near-identical prices. Most hours, the gap between Europe's highest and lowest zones stays inside €100.

On Sunday 26 April midday, that gap blew past €600. Central and western Europe crashed to nearly negative €500/MWh. Spain cleared just below zero. Ireland held at €141. Three regimes inside a single hour, separated only by how much copper connects them.

Three years ago, this would have been a curiosity. It's becoming a fixture of spring weekends as solar growth outruns the grid.

The next three beats zoom into each:

• The European core — when there's no spare cable, the whole cluster crashes together
• British Isles — same Atlantic weather, two markets, two prices, courtesy of Brexit
• Iberia — well-connected internally, barely linked to the rest of Europe

Each shows what happens when the wires can't keep up.

European prices have run elevated for months, ever since February's Hormuz crisis cut a tenth of Europe's LNG supply — the baseline has held near €100/MWh. Sundays soften with industry off. On 26 April, conditions aligned: solar at peak, demand at the weekly low — too late in the year for heating, too early for cooling. Wind was near zero, and the crash happened anyway. What happened?

By Sunday midday, the shared market had nowhere left to push the surplus. More than 8 GW of unwanted power was on the system. The auction drove the price down in steps — each one deep enough to force another tier of inflexible generators to give up and switch off rather than pay to keep running. The floor settled near -€413/MWh — deep enough to dislodge even the most subsidised solar and wind. Nice for consumers. Terrible for generators.

The shared market works both ways. Strip the sun and add cold-weather demand, and the same windless system inverts. December 2024's "dunkelflaute" did exactly that: no wind, no sun, peak heating demand, not enough imports from neighbours to ease it. The same connected continent sent Germany to €823/MWh on a Thursday afternoon. Same generators, same wires, opposite kind of shortage.

The British Isles are islands, and their cable connection to continental Europe is finite — 9 GW of HVDC from Britain, 1.5 GW between Ireland and Britain. When those cables fill, as they did on Sunday, physical capacity (not market design) becomes the binding constraint.

With wind quiet across both islands, cable access decided the price. On Sunday 26 April midday, Britain cleared at €90 while Ireland held at €141. The roughly 1.5 GW of cable between Ireland and Britain was already full, leaving Ireland's gas plants to set the price for its own demand at this year's Hormuz-inflated gas costs. Britain drew on all 9 GW of its cables — and one of those routes was carrying more than just local power.

When central and western Europe crashed to negative €413 on Sunday midday, the cable between Germany and southern Norway ran north — Germany pushing about 380 MW of surplus into Norwegian hydro reservoirs near Stavanger. At the same time, the cable from southern Norway to Britain ran south at full capacity (1.4 GW). Norway became a transit zone: soaking up the European surplus on one coast while exporting to British demand on the other. Southern Norway cleared at €33. Bergen, just up the coast, paid €97 — because the internal Norwegian grid between them couldn't share Stavanger's bargain.

The Celtic Interconnector (700 MW, due in 2027) will give Ireland its first direct line to the continent. Until then, the Irish Sea is an electrical border as much as a geographic one — and the Channel is busier than the map suggests.

Spain and Portugal run as one electricity market and share a roughly 3,000 km internal grid. But they have just 2.8 GW of cable connecting them to France — the lowest in Europe relative to demand, and well below the EU's target of 15%.

When solar floods Iberia on a sunny midday, the surplus has nowhere to escape. Prices crash hard inside Spain and Portugal — they cleared near zero across the week's sunniest hours — but the wires to France can't relieve the glut. The same pattern works in reverse during evening peaks: when neighbours try to export power in, the trickle through the Pyrenees can't soften Iberia's price. Italy is the sibling case across the Alps — same partial isolation, but with so much more gas in its mix that solar surplus never crashes its price the way it does in Iberia.

The risk isn't only price. On 28 April 2025, the entire peninsula lost grid stability for hours. The grid's frequency dropped suddenly across Spain and Portugal, and the small link to France didn't have the capacity to import enough power — or borrow enough stability from the larger European grid — to catch it. The Pyrenees are a market boundary AND a resilience risk. A new 2 GW cable under the Bay of Biscay, due in 2028, is the partial fix.