Why electricity markets are stuck on the gas price rollercoaster

Welcome back.

Few markets have ever had swings quite like those seen recently in European wholesale power prices. When the sun is shining and the wind is blowing, these can be very low indeed. On Sunday, the price in Germany hit an extraordinary record of minus €413.88 per megawatt-hour (see my earlier primer on the odd phenomenon of negative electricity prices).

But when renewable and nuclear power plants aren’t able to satisfy all demand, grid operators need to turn to much more expensive gas-fired power, which raises the price for the whole market (especially strongly when the Strait of Hormuz is blocked). That’s nice for the generators; less so for the rest of the economy.

Is it time to rethink how these markets work?

Breaking up with gas prices is hard to do

“We need to get off the fossil fuel rollercoaster,” UK Prime Minister Sir Keir Starmer said last week.

The statement came as his government unveiled new policies to tackle a problem that has become politically hot across Europe amid the conflict-driven energy market turmoil of the past two months.

Growing renewable power generation means that natural gas combustion now accounts for a modest share of total electricity supply: about a quarter in the UK, and less than a fifth in the EU. Yet the structure of the market means that most of the time, gas-fired plants still set the wholesale electricity price — which has therefore moved higher since the outbreak of the US-Israel war with Iran.

The government promised with a heavy dose of hyperbole that the new UK package would “break [the] influence of gas on electricity prices”. Unfortunately for Starmer — and for other European leaders — the path to eliminating that influence remains far from clear.

The market mechanics

At the centre of the conundrum is the “marginal pricing” system used in Europe’s electricity markets. Throughout each day, generators submit bids to grid operators with the price at which they’re willing to sell power. The lowest bids generally come from renewable power producers (unsurprisingly, since they don’t have to pay for fuel); the highest from fossil fuel plants.

The market operator accepts as many of these offers as are needed to meet demand for the period in question, favouring the cheapest ones. Each generator receives not the price they’ve bid, but rather the market clearing price: that is, the highest bid from among those chosen, or the cost of the final “marginal unit” needed to meet demand.

Imagine, for example, that a market operator needs 10 units of electricity. It has nine solar generators, each offering one unit at about €30, and several gas generators, each offering one unit at much higher prices, of which the cheapest is €100. Under this system, it would get nine units from the solar producers and one unit from the cheapest gas generator — and everyone would be paid €100 per unit, even though the solar producers were willing to accept far less.

In search of a remedy

Is there a better way of doing things? The UK government has looked seriously at the idea of zonal pricing, which would involve splitting the country into several markets, each with its own price. The idea has been championed by Octopus Energy, the country’s biggest electricity retailer, which argued it would reduce average power prices while encouraging industrial investments close to cheap green power sources.

The government canned that option last year, reasoning that it would create “unnecessarily high instability and uncertainty around future prices and zonal boundaries, which would be passed onto consumers in the form of higher prices”.

Instead of radically reforming the wholesale power market, the government is trying to take more generation out of it.

Since 2014, the bulk of new UK renewable plants have agreed to sell their power for fixed prices through the government’s contract for difference (CFD) scheme. But a large amount of renewable power — accounting for almost a third of all the UK’s electricity generation — is still sold through the wholesale markets, for prices that rise when the gas price does.

Last week the government announced a new scheme that will enable operators of already existing renewable plants to sign up for CFDs, which are usually inked before a plant starts operating. To encourage them to do so, the government will raise an electricity windfall tax — imposed when prices reach unusually high levels — from 45 to 55 per cent.

The measures “will further reduce the share of electricity exposed to gas price shocks”, the government promises. How far it does so will depend on the terms of the new scheme, which have yet to be announced — and which will need to be sufficiently attractive for power producers to give up the sort of revenue bounce they’ve enjoyed over the past two months.

But under any scenario, a big portion of UK electricity will continue to be sold through wholesale markets — where gas will still set the price about half the time in 2030, according to the government’s own forecast.

The EU debate

Electricity market price design has fallen under the spotlight in the EU too, where high power prices have been a central feature of the angst-ridden debate over the bloc’s economic competitiveness. A February meeting of EU leaders featured “intense discussion” on the problem of electricity market prices being set by “the most expensive resource”, European Commission president Ursula von der Leyen said afterwards, promising to explore “whether it is time to move forward on the market design”.

One option, proposed by Italy, would mean in effect subsidising gas power producers to enable them to offer power at lower prices, thereby lowering the market price received by all generators.

Another would involve splitting the power market into renewable and non-renewable “pools”, each with different prices. Still another would see each producer paid whatever they bid, rather than the market clearing price.

Such ideas are drawing stiff resistance. Last month, seven EU member governments, including the Netherlands, Portugal and Sweden, wrote to EU energy commissioner Dan Jørgensen arguing against tinkering with the marginal pricing system. This would “introduce inefficiencies through inaccurate price signals caused by an increase in strategic bidding patterns”, potentially driving consumer prices higher, they warned.

The power industry, too, has been lobbying hard against radical changes to the market structure, arguing that this would cause huge disruption and uncertainty. “This is not the time to throw out a basically well-functioning system,” said Kristian Ruby, secretary-general of Eurelectric, the trade organisation of the European electricity sector.

Ruby argued that the current market model was gradually succeeding in reducing gas’s influence on power prices, with gas-fired power required for a steadily decreasing number of hours as renewable penetration grows. Accelerating investment in grid-level power storage — spurred by a dramatic fall in battery prices over the past two years — is further eroding the need for gas power at night or when the wind’s not blowing, Ruby told me.

Last week the European Commission announced a suite of proposed measures to reduce disruption from fossil fuel price swings, with no mention of a restructuring of the electricity market. Instead, it recommended temporary measures such as targeted income support schemes and energy vouchers, along with a broader push to accelerate green power investment.

“Already today, member states with more low-carbon sources in their energy mix are less impacted by the crisis,” von der Leyen told the European parliament in a speech earlier today. “This is how we insulate ourselves from future shocks.”

No easy answers

A useful case study here is Spain, which has among the highest rates of solar and wind generation in Europe. Gas-fired generation influences Spanish wholesale power prices in only 15 per cent of hours, compared with 89 per cent in Italy, according to analysis by Ember, using data for the first 10 weeks of this year. So far this year, the average Spanish wholesale power market price has been €43.43, compared with €128.14 in Italy.

Wholesale prices, which reflect generation costs, only show part of the picture, pointed out Brett Christophers, a professor at Uppsala University and author of The Price is Wrong: Why Capitalism Won’t Save the Planet, a book on the economics of renewable energy.

The wholesale power cost is just one element of a household or business’s electricity bill, along with charges that cover the costs of building and maintaining the power grid. So while renewable power might be lowering the average cost of generation, “if the cost of transmission and distribution is going up, then that’s an offsetting factor”, Christophers said.

The shift from fossil-fired generation will require huge investment in transmission to deliver power to high-demand areas from wind and solar farms, as well as investment in battery storage and more interconnections between national power systems. For some years to come, that will limit the extent to which consumers will enjoy the price benefits of low marginal-cost renewable generation.

Beyond the absolute price level, however, it’s important to consider the damaging effects of wild energy market swings for the economy as a whole, argues Laura Díaz Anadón, a professor at Cambridge university and co-author of a 2025 paper that modelled the potential for higher levels of renewable power to support investor-friendly macroeconomic stability. “Policymaking in general has not taken into account this insurance value of renewables”, she told me.

The latest gas market shock — following the still more severe one of 2022 — has further strengthened this case for expanded renewable energy investment. Green power may not enable Europe to step off the gas price rollercoaster altogether any time soon. But it can significantly soften the hair-raising twists and turns.

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