Why Electricity Prices Spike: Merit Order, Gas and Scarcity

Few traded commodities are as volatile as wholesale electricity. On a single European day, an hour of power can cost less than nothing at noon and several hundred euros per megawatt-hour at 7 pm. Over longer periods, a fuel supply disruption can multiply the average price, as it did across Europe in 2021–2022. None of this is mysterious. It follows from how markets pick which plants run, how little electricity can be stored, and how fuel and carbon costs feed into the most expensive plant online. Below we go through each driver with typical numbers, then look at what a household can do about it.

The merit order: why the last plant sets the price

Most wholesale markets (the European day-ahead coupling, PJM, ERCOT, Australia’s NEM) use uniform marginal pricing. For every hour or 15-minute interval, generators submit offers. The operator sorts them from cheapest to most expensive (the merit order) and works up the stack until supply meets demand. Every dispatched unit then receives the offer price of the last unit needed, called the clearing price.

Generators bid close to their short-run marginal cost, meaning the cost of producing one more MWh:

These ranges illustrate European conditions over the past decade. Actual values move with fuel and carbon prices.

Worked example: gas at €35 versus €150

Take a CCGT at 55% efficiency, with carbon at €70/t and variable O&M of €3/MWh:

• Gas at €35/MWh_th: 35 / 0.55 = 63.6; carbon 70 × 0.20 / 0.55 = 25.5; plus 3 → SRMC ≈ €92/MWh.
• Gas at €150/MWh_th: 150 / 0.55 = 272.7; carbon 25.5; plus 3 → SRMC ≈ €301/MWh.

If that CCGT is the marginal unit for most hours, the wholesale price roughly triples, and every wind farm, solar park and nuclear station in the same bidding zone collects the tripled price as well. This is what happened in 2022. European benchmark gas (TTF) traded at several times its pre-2021 level for months, briefly topping €300/MWh in August 2022, and power prices followed.

Why electricity is so sensitive: inelastic demand and no storage

Two physical facts amplify price moves.

In the short term, demand hardly responds to price. Most consumers never see real-time prices, and those who do can’t easily stop cooking or heating at 6 pm. The demand curve is almost vertical.

Supply gets steep at the top. The last few gigawatts come from old, inefficient peakers or emergency units with very high costs. Once demand climbs into that steep section, say on a cold, windless evening, a small rise in demand can double or triple the clearing price.

Put a near-vertical demand curve against a hockey-stick supply curve and prices become extremely sensitive. Near the peak, a 2–3% change in available supply can move them by hundreds of euros.

The main causes of price spikes

1. Fuel price shocks

In many European countries gas sets the marginal price in a large share of hours, a point ACER’s 2022 market-design assessment discussed. When gas prices rise, electricity follows almost one-for-one in gas-marginal hours. Where coal is marginal, coal and carbon prices work the same way.

2. Scarcity hours

On a cold winter evening with little wind and no sun, demand peaks exactly when variable output is lowest, and operators may have to dip into reserves. Markets cap prices to limit the extremes. The European day-ahead harmonised maximum clearing price went from €3,000 to €4,000/MWh in 2022 after prices hit the old limit, and the rules now let it rise further when prices approach it. ERCOT in Texas allows prices up to $5,000/MWh. During Winter Storm Uri in February 2021, ERCOT prices stayed at the then-cap of $9,000/MWh for days while gas supply froze and load was shed.

3. Unplanned outages and low hydro

Every large plant that drops out tightens the stack. In 2022, stress-corrosion inspections pushed France’s nuclear output to its lowest level in decades, and France, normally a net exporter, became a net importer for the year. That same summer, drought cut hydro output across southern Europe and reduced the river cooling available to thermal plants.

4. Network congestion

When interconnectors are full, prices diverge between bidding zones. A zone that can’t import cheap power from its neighbours has to run its own expensive plants. US nodal markets (PJM, ERCOT, CAISO) price congestion at each node, so prices can spike in one city and stay low a few hundred km away.

5. Weather and forecast errors

A wind forecast that misses by a few gigawatts can send intraday and balancing prices sharply up or down. Heatwaves push up air-conditioning demand and lower thermal plant efficiency at the same time.

Negative prices: the other extreme

As wind and solar grow, prices fall to zero or below more often in sunny, windy, low-demand hours. Spring weekend middays are the classic case. Prices turn negative because stopping costs some generators money: plants on per-MWh subsidies still collect the subsidy, inflexible thermal units face expensive restarts, and some contracts require delivery. Market data compiled by Ember and national operators show Germany, the Netherlands, Spain and South Australia recording hundreds of negative-price hours a year recently.

The gap between negative middays and expensive evenings is what makes batteries and flexible demand valuable. It also explains why solar’s capture price (the average price its output actually earns) drops below the baseload average as more solar is built, an effect known as “cannibalisation”.

How spikes reach consumers

Wholesale energy is only part of a retail bill. Network charges, taxes, levies and supplier margins often account for 40–60% of a European household price, so when wholesale prices double, the bill does not.

What households can do

• Shift flexible loads. EV charging, dishwashers, water heaters and heat pumps with buffer tanks can all run in cheap hours. Our EV charging cost calculator shows what a cheaper overnight rate saves per year.
• Self-generate. Rooftop solar replaces retail electricity, which is less volatile than wholesale but still rises with it. The net metering calculator shows how export credits change the economics.
• Store. On a dynamic tariff, a home battery can arbitrage daily spreads. Size one with the solar battery calculator. Paying back on arbitrage alone usually takes a spread of €0.10–0.20/kWh on most days.
• Lock in when it makes sense. A fixed-price contract moves the risk to the supplier, and you pay a premium for that insurance.

The example assumes a generous 23-cent average spread. At 8–10 cents you get less than half the value, which is why arbitrage-only payback varies so widely.

What reduces spikes at the system level

Policymakers and grid planners have several levers, each with trade-offs:

• More interconnection pools resources across wider weather systems.
• Storage and demand response flatten the evening peak and soak up midday surplus.
• Long-term contracts (PPAs, contracts for difference) protect both generators and consumers from short-term prices. The EU’s 2024 market-design reform encourages two-sided CfDs for new low-carbon plants.
• Capacity mechanisms pay for firm capacity to be available in scarcity hours.
• Moving away from gas cuts how often gas is the marginal unit. Lower lifetime costs, as the LCOE calculator shows, don’t lower the marginal price on their own. But enough zero-marginal-cost supply pushes gas further up the stack and out of more hours.

To see which countries depend most on gas and which grids lean on hydro, nuclear or wind, browse the country profiles or compare generation mixes on the world energy map. For the physical side of balancing supply and demand, read how the power grid works.

Figures in this guide are typical ranges drawn from the sources above; your own numbers depend on location, prices and equipment. Use the linked calculators for site-specific estimates.