On the eve of the European Council meeting on March 19 and 20, Eurelectric published an information document prepared by NEON to provide analytical recommendations as a basis for the upcoming discussions.
The document is divided into three parts.
The first part examines the question of whether energy prices in Europe are really that high – the current situation is radically different from energy prices in 2022 – in fact, prices have largely returned to their pre-crisis levels. However, large price differences continue to exist in Europe. While in some parts of Europe electricity prices are extremely competitive internationally, in others industry and consumers continue to face higher prices compared to parts of the US. The main factor behind this structural price difference is natural gas, which is three times cheaper in the US than in the EU. Although this difference can be reduced, it cannot be completely eliminated.
Second, the memorandum raises the question of whether the current market structure, based on marginal pricing, is the optimal system for ensuring a functioning, clean electricity system. It shows that marginal pricing is often used in commodity markets and illustrates its functioning through a simple analogy with commodities. It is emphasized that marginal pricing is a standard feature of electricity markets worldwide, including in North America. The analysis concludes that marginal pricing remains the most efficient allocation mechanism, as it ensures that priority is given to the lowest-cost generation, and debunks some of the main “myths” about marginal pricing.
Third, it asks what the effects of the proposed changes to the market model would be. Some of the alternatives to the current scheme are analyzed in detail. Two proposals are considered: (i) the “Iberian-Italian mechanism” (gas subsidy) and (ii) the “Capros proposal” (market splitting). The analysis shows that the existing design provides the greatest benefits to consumers and that the alternatives would either lead to the same results with a more complex electricity system or to more expensive electricity for consumers.
Summary of the analysis “Marginal pricing and the merit order: why the proposed state interventions in the wholesale electricity market are a bad idea”
Context
On February 12, 2026, following an informal meeting of the European Council in Alden Beizen, European Commission President Ursula von der Leyen raised the question of whether the current design of European wholesale electricity markets is still adequate. The discussion is scheduled for the European Council meeting on 19-20 March 2026. In parallel, several Member States, including Italy and Austria, have proposed specific interventions in the price formation mechanism. The analysis, prepared by the Berlin-based consulting firm Neon Neue Energieökonomik on behalf of Eurelectric, provides an analytical basis for this discussion. The memo examines three key questions: whether European electricity prices are indeed high, whether marginal pricing works effectively, and what the consequences of the proposed interventions would be.
The price situation: far from the crisis of 2022
The authors make a clear distinction between the current price environment and the energy crisis. In 2022, average electricity exchange prices in Germany reached €270/MWh (adjusted for inflation), with futures contracts exceeding €1,000/MWh in August of that year. Today, exchange prices are below €90/MWh, which is a 90-95% drop from the crisis peak. This is a fundamentally different situation, and the application of crisis measures in a normal market environment is unjustified.
At the same time, the analysis acknowledges that in certain parts of Europe, prices remain relatively high by international standards. Exchange prices vary significantly, from around €30/MWh in Scandinavia and €50/MWh in France to €80/MWh in Germany and close to €100/MWh in Eastern and Southeastern Europe. The differences reflect local supply conditions: the Iberian Peninsula relies on cheap wind and solar generation, France on its nuclear fleet, and the Scandinavian countries on abundant water resources.
The Germany-Texas comparison: market design is not the problem
To illustrate the structural price difference between Europe and the US, the analysis compares Germany and Texas. Futures prices in Germany are around €80/MWh, while in Texas they are around €45/MWh. However, this difference of approximately €35/MWh is not due to differences in market design: Texas also applies marginal pricing and even goes further by using nodal (location-based marginal) pricing, which also reflects the marginal costs of the transmission network.
The two main factors explaining the price difference are natural gas prices and carbon pricing. Natural gas in Europe is about three times more expensive – approximately €30/MWh compared to €10/MWh in Texas – due to dependence on liquefied natural gas imports. This difference makes electricity from gas-fired power plants about €40/MWh more expensive. Given that gas-fired power plants determine the exchange price about half the time, this alone explains about €20/MWh of the difference. The second factor is the European Emissions Trading System (EU ETS), which, at current carbon allowance prices, makes electricity from gas-fired power plants about €25/MWh more expensive, and electricity from coal-fired power plants twice as expensive. Given that coal determines the price in about 10% of the hours, carbon pricing adds another €20/MWh. Taken together, these two factors fully explain the structural difference in exchange prices.
Certain energy policy decisions also have an additional impact: slow and expensive network expansion, delayed introduction of smart meters, lack of location signals in tariffs, and premature decommissioning of nuclear and coal-fired power plants.
Marginal pricing: a standard market mechanism
The analysis defends the thesis that marginal pricing is neither specific to electricity nor an artificially imposed rule. It is the standard way in which prices are formed in all competitive commodity markets—from oil and gas to copper and wheat to airline tickets and cloud data. The equilibrium market price is established where the marginal willingness of buyers to pay for an additional unit equals the marginal cost of producing it.
The Merit Order curve is simply a short-term supply curve showing the variable costs of different generating capacities, mainly for fuel and carbon allowances. It does not include investment and fixed costs. The only peculiarity of the electricity market is that, due to the impossibility of storage, market equilibrium is determined every quarter of an hour, rather than once.
The author emphasizes that the marginal price is the only price at which there is effective market clearing—the quantity supplied matches the quantity demanded. Any artificial reduction in price creates a supply shortage and requires the introduction of a redistribution regime, in which the state decides who gets their “share” of cheap electricity and who does not.
The difference between the exchange price and the variable costs of producers, or the so-called “contribution margin,” is often confused with “excess profit.” In fact, it is this margin that covers investment and maintenance costs. For example, a new nuclear power plant requires daily revenue coverage of around €4 million for 60 years to recoup investments of around €20 billion. For a new nuclear power plant, for example, a daily revenue coverage of around €4 million is needed for 60 years to recoup investments of around €20 billion.
The analysis refutes eight common misconceptions: that marginal pricing is unique to the electricity market (it is not), that the merit order curve is a mandatory rule (it is a descriptive model), that “pay-as-bid” would lead to different prices (it would not, as participants would immediately adapt their strategy), that the exchange price is “linked” to the price of gas by law (the link is economic and depends on whether gas-fired power plants determine the price, i.e., are closing plants at the time) etc.
Proposed interventions: more harm than good
Two main proposals are on the agenda. The first is the so-called “Iberian Mechanism 2.0,” proposed by Italy, which subsidizes gas-fired power plants (or exempts them from carbon emissions payments) to reduce their bid prices on the exchange, with the cost of the subsidy recovered through a tax on electricity consumption. The second proposal, “market split,” proposed by the Austrian government based on an idea by Prof. Pantelis Kapros, envisages dividing the wholesale market into two segments: one for RES and one for conventional power plants.
Regarding the “Iberian mechanism,” the authors point out that the conditions under which it was relatively effective in Spain and Portugal in 2022 (extremely high gas prices, low share of gas generation, high share of low-carbon generation, weak cross-border connectivity) are far from being present in the current situation. At current price levels, the effect of the mechanism would be minimal, and hedged consumers would bear the costs of the new fee without benefiting from lower exchange prices. This discourages hedging and increases consumer vulnerability to future price volatility.
Regarding “market splitting,” the analysis notes that fundamental questions remain unanswered: how will cheap energy from RES be distributed among consumers, how will cross-border market coupling work, how will intraday and balancing markets be organized.
Where will the money come from?
The central argument of the analysis is that artificially lowering exchange prices does not reduce real system costs, but simply redistributes them. The analysis looks at three categories of producers and shows why the effect is limited or counterproductive for each of them.
In the case of subsidised RES (which, for example, provide over 50% of electricity in Germany), support schemes – feed-in tariffs and two-way contracts for difference (CfD) – automatically compensate for the fall in exchange prices by increasing subsidies. Every euro saved by consumers on the exchange is returned as a higher subsidy fee.
For conventional power plants, whose variable costs at current gas and carbon prices reach €90-110/MWh for gas and €80-90/MWh for coal-fired capacity, a significant drop in the exchange price would make them unprofitable. However, if these plants are necessary for security of supply, they would be compensated through network reserves or other mechanisms financed by network tariffs.
For nuclear and hydroelectric power plants, which provide about one-third of European electricity, full maintenance costs are estimated at €50-70/MWh for existing nuclear capacity. In many Member States, these plants are state-owned and the loss of revenue is ultimately covered by taxpayers.
Conclusion
Neon’s analysis reaches three main conclusions. First, the current price situation is fundamentally different from the crisis of 2022 and does not justify extraordinary interventions. Second, marginal pricing is a standard, efficient market mechanism that ensures optimal dispatch, correct investment signals, and security of supply. Third, the proposed interventions would distort market signals, undermine investor confidence, and fail to achieve a real reduction in end prices for consumers—savings from lower exchange prices would be offset by increased subsidies, network charges, and taxes. There are effective policy instruments for reducing prices — targeted support for vulnerable consumers, structural reforms to increase the efficiency of the system — but intervention in the market price formation mechanism is not one of them.
Full text of the report
