Industry follows working hours. Households follow schedules. Heating follows weather. The result is a familiar shape: a morning ramp around 6 a.m., an evening peak around 7 p.m., a long overnight trough. 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.

The day-ahead auction stacks generators from cheapest to most expensive until enough capacity clears to meet demand. Solar and wind go first at zero marginal cost. Nuclear and hydro fill in. Gas, coal, and oil sit on top.

The last megawatt-hour clearing in the auction sets the price for every plant in it. 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. The signal is the price spread between connected zones. Bigger spread, bigger flow, until the wires are full.

The same friction exists inside countries, not just across borders. Germany is the textbook example. Wind built on the North Sea coast struggles to reach load in Bavaria and Baden-Württemberg, and the four planned north-south corridors (SuedLink, SuedOstLink, Ultranet, A-Nord) are years late. Because Germany clears as a single bidding zone, the congestion doesn't show in the day-ahead price; it shows up as around €30 bn a year of redispatch and curtailment costs. Outside Germany the picture is similar. Iberia sits behind only 2.8 GW of AC interconnection to France, and connection queues for new generation across most of Europe are measured in years.

Wind is the cheapest electricity Europe can produce: zero fuel cost, no carbon. Around 245 GW of capacity is onshore, spread across most member states with the largest fleets in Germany, Spain, France, and the British Isles. About 35 GW is offshore, concentrated in the North Sea: the UK, Germany, the Netherlands, Belgium, and Denmark. 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 storage, flexible demand, or an interconnector to somewhere with different weather can absorb the surplus.

Solar peaks predictably in a way wind never has. Germany has Europe's largest fleet by a wide margin, with around 115 GW installed — more than twice Spain and Portugal combined (~50 GW). Italy sits at about 37 GW, the Netherlands at ~30 GW, and France at ~25 GW. Capacity has been added across every member state over the past five years.

Midday is now the cheapest hour in sunny markets. That inverts the old price curve: peak demand is still evening, peak supply is noon. The question is who absorbs the surplus. Batteries that charge for the evening, electrolysers running on cheap power, factories shifting production into the cheap hours, interconnectors to neighbours under cloud. All of them get more valuable as solar saturates more days.

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. About 15% of the energy is lost to round-trip inefficiency. So the discharge price has to be at least 20% higher than the charge price for the trade to break even. Anything above that is margin.

At scale, the fleet flattens the duck curve. It absorbs solar surplus at noon and softens the evening peak that gas would otherwise serve. The UK leads with the largest measured grid-scale fleet, dispatched twice a day against half-hourly prices. Italy's storage capacity auctions are scaling a comparable fleet across the seven Italian subzones. Germany, Ireland, and the rest are early but moving quickly.

Reservoir hydro is the largest effective battery in Europe. By energy stored, it sits orders of magnitude beyond every grid-scale lithium fleet on the continent combined. The Norwegian and Swedish fleets are the bulk of it. The Alpine countries (Switzerland, Austria, Italy) and the Pyrenees add the rest.

Operators hold water back when wind and sun are plentiful and release it when neither is. NordLink and the North Sea Link turn that mountain geography into a shared European resource. A Norwegian reservoir can balance an English afternoon. The dam-building era is over on the continent. Environmental rules, NIMBY, and the simple fact that Europe has run out of viable rivers closed it. The value left in hydro is optionality: when to release, on what timescale, against which neighbour's price.

Gas plants fire up when nothing cheaper can serve the load: solar fading, demand rising, the evening ramp underway. 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. So a cold snap in Texas can move European power prices days later. So can a freight disruption in the Strait of Hormuz.

Gas is no longer the volume-mover it was twenty years ago. Renewables and nuclear carry more megawatt-hours now. 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. Less fuel burned, more price leverage per megawatt-hour, and a price line that now rides global LNG.

France runs around 45 GW continuously, hour after hour. The UK runs a few. Belgium, Spain, Switzerland, Finland, and most of Central Europe each hold smaller but similarly flat blocks. Germany and Italy don't run any.

Nuclear's value is that it doesn't cycle. Most of the fleet was built in a single burst between the 1970s and 1990s, and a lot of the capital and expertise retired with it. Six countries are publicly planning new builds: Poland, the Netherlands, Czechia, Slovakia, the UK, and France. All of them are working on timelines measured in decades. What still runs delivers something nobody else can deliver without firm gas or firm storage: flat, predictable, always-on megawatts.

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. 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. Poland's transition is the biggest unresolved question in European power: when, with what generation, and at what political cost.

Offshore wind at capacity. Solar at peak. Demand in mid-shoulder: a summer weekend, nobody heating, factories quiet. Residual load, the part thermal has to serve, collapses toward zero for hours. The day-ahead auction prints negative across large parts of the continent.

Nice if you're a consumer. Terrible if you produce the power.

Negative prices are a tax on inflexibility. A generator that can't ramp off pays to keep running. A battery that charges here sells the same energy five hours later at the evening peak. Demand shifted into these hours effectively gets paid to consume. Days of free electricity, for anyone with somewhere to put it.

Thick overcast across the North Sea. No wind. No sun. Winter heating at peak. Thermal ramps up, imports saturate, and the day-ahead price does something the standard models don't comfortably handle. On Thursday 12 December 2024 at 16:00, Germany cleared at €823/MWh.

Events like this don't happen often. When they do, the system needs every megawatt it can find. A plant that only runs a few weeks a year can't pay for itself from those hours alone. That's why Germany is launching a capacity market, joining France, Belgium, Italy, and the UK. Firm capacity has to be paid to exist, not just to run.

Then the question becomes what kind of firm capacity. Long-duration storage would be the cleanest answer, but it's still years from commercial viability. Pumped hydro is the only mature long-duration storage Europe has, and its dams are already built. Lithium batteries get prohibitively expensive past 4–6 hours of duration. For now, Europe still needs gas on standby. In a few markets, coal too. Both get paid to exist for the handful of winter weeks when nothing else can cover.