Marginal Cost · Glossary

Marginal cost is the additional cost incurred when a plant generates one more unit of electricity. In the electricity market, this unit is usually one additional megawatt hour, and the cost is stated in euros per megawatt hour (€/MWh). For a gas-fired power plant, this mainly includes fuel costs, costs of CO₂ allowances and variable operating costs, such as usage-dependent wear and auxiliary materials. In the energy industry, short-term marginal costs are therefore often equated with variable costs. For wind and solar plants, they are close to zero, because no fuel has to be bought for an additional kilowatt hour.

The term therefore does not describe the total costs of a power generation plant. Construction costs, financing, land lease, planning, grid connection, personnel, maintenance contracts and decommissioning costs still exist, even if they do not appear in short-term marginal costs. Marginal cost answers a narrower question: what does it cost additionally to have this plant generate a little more electricity right now, provided it is technically available and the energy source is on hand?

It is precisely this narrow scope that makes the term so important in the electricity system. Generation and consumption must match at every moment, either through power plants or through storage. For short-term power plant dispatch, what matters first is therefore not which plant is cheapest over its lifetime. What is decisive is which available plant can deliver the next required megawatt hour most cheaply. This is exactly where marginal costs take effect in the merit order.

A Worked Example

A simplified calculation with example values shows how the marginal cost of a gas-fired power plant is composed. These are not current market prices. Suppose natural gas costs €35/MWh thermal and the plant has an electrical efficiency of 55 percent. One megawatt hour of electricity then requires about 1.82 MWh of gas, which amounts to roughly €64 in fuel costs. Natural gas releases roughly 0.2 tonnes of CO₂ per MWh thermal when burned. Per MWh of electricity, that is about 0.36 tonnes, so at a CO₂ price of €70/t it comes to around €25. With a few euros of variable operating costs, the result is marginal costs of around €90/MWh. If the gas price or the CO₂ price rises, marginal costs rise almost proportionally. An older plant with lower efficiency reacts even more strongly.

CO₂ costs are included in marginal costs even if an operator was previously allocated allowances free of charge. An allowance that is not used for the operator's own production could be sold. Its market value is therefore an opportunity cost component of electricity generation.

Marginal Cost, Average Cost and Levelized Cost of Electricity

Marginal costs are often confused with average costs or levelized cost of electricity. Average costs spread the total costs of a plant over the quantity of electricity generated. Levelized cost of electricity is usually the discounted cost per megawatt hour averaged over the lifetime. Both measures are suitable for comparing investments. However, they say little about which plant is dispatched in a particular quarter hour or hour.

A fully depreciated coal-fired power plant can have low capital costs and nevertheless high marginal costs if fuel and CO₂ are expensive. A new photovoltaic plant has high initial investment costs but very low marginal costs in ongoing operation. A battery storage system needs no fuel. However, its marginal costs depend on the value of the electricity previously stored, as well as on efficiency losses, ageing caused by charging cycles, and whether it could later discharge at a higher price.

Fixed costs must also be clearly delimited. They are incurred regardless of whether a plant produces in a particular hour. Marginal costs arise only from the additional production. For the short-term dispatch decision, fixed costs are usually not decisive, but for investments and security of supply they very much are. A market that sorts by marginal cost in the short term therefore needs a framework under which capacity that runs only rarely can also be financed.

Role in Price Formation in the Electricity Market

Electricity is traded on the wholesale market in several market segments: through long-term forward contracts, over the counter and on the exchange. The day-ahead market is particularly visible. In the EU, the national day-ahead markets are linked through the common market coupling SDAC. Since the delivery day of 1 October 2025, prices there have been determined in 15-minute intervals instead of hourly. Suppliers submit bids that, in a competitive market, should be based on their marginal costs. Demand is met with the cheapest available offers. Under the uniform-price procedure (pay-as-cleared), all accepted quantities receive the same market clearing price.

It is often said in shorthand that the most expensive power plant sets the electricity price. More precisely: the last unit needed to meet demand determines the price in the respective bidding zone and trading period. This is also called the marginal power plant. This unit can be a gas-fired or coal-fired plant, a storage facility, flexible demand or, in times of scarcity, a bid that expresses the value of undelivered or shifted demand. The price therefore does not value any technology. It results from the sorted available bids and the respective demand, whereby transmission capacities between bidding zones are also taken into account.

That all successful suppliers receive the same price is intended. Under full competition, it pays for a small supplier to bid roughly its actual marginal costs. A higher bid increases the risk of not being awarded. A lower bid does not reduce the payout price, but can lead to losses if the market clears below the supplier's own costs. Plants with lower marginal costs than the marginal power plant earn a difference, the contribution margin. From this they must cover their fixed costs. In practice, this ideal is limited by market power, forecast errors, technical minimum loads, start-up costs and strategic behaviour. Nevertheless, the marginal cost principle explains why the short-term electricity price reacts so strongly to fuel prices, CO₂ prices, the availability of power plants and the feed-in from renewable energies. This became clearly visible in 2022, when sharply increased gas prices pushed up the marginal costs of gas-fired power plants and with them wholesale prices.

Price formation has technical limits. In the European day-ahead market, harmonised maximum and minimum prices apply. The reference value is +€4,000/MWh and −€500/MWh. The upper limit is raised automatically under defined rules if prices repeatedly come close to it.

Why Low Marginal Costs Do Not Mean Low Total Costs

Wind and solar plants have very low marginal costs in operation. They shift the merit order to the right and lower the exchange price in hours with high renewable feed-in. This is called the merit order effect. With very high feed-in and low demand, prices can fall to zero or become negative. Electricity does not physically have a negative value then. Rather, negative prices show that in this situation there are costs or technical hurdles to curtailing generation, increasing consumption, storing electricity or transporting it to other regions. One reason is support or contract schemes under which plants earn revenues even at negative prices. Another is plants that keep running because of heat supply or system services.

Low marginal costs of renewable plants also do not mean that an electricity system based on renewable energies can be operated free of charge. Plants, grids, storage, controllable loads, reserve capacity, metering and communication technology and system services must be financed. Marginal costs make visible why renewable energies can push down the short-term market price. They alone do not explain what costs arise for a reliable, spatially balanced electricity system that functions at all times.

This gives rise to a common misinterpretation in electricity price debates. An exchange price that is low in many hours does not automatically lead to a correspondingly low household electricity price. End-customer prices include grid charges, levies, surcharges, taxes, sales costs, procurement strategies and risk premiums. Moreover, suppliers purchase a large part of their electricity through forward and supply contracts and not at the current spot price. Wholesale marginal costs therefore do affect the electricity bill, but only with a time lag and via these intermediate stages.

Technical Limits of the Marginal Cost Principle

Power plants cannot be regulated arbitrarily. Many plants have a minimum load, start-up times, limited ramp rates, load-dependent efficiency and wear costs. A gas-fired power plant that is already running has different marginal costs than the same plant before start-up, because start-up costs would still be incurred. A coal-fired power plant may keep running even at temporarily low prices if shutting down and restarting would be more expensive. In combined heat and power, heat supply is added as a constraint. Hydropower plants must take into account inflows, reservoir levels, ecological requirements and the future value of the water.

For storage, an opportunity value takes the place of classical fuel costs. Anyone who discharges a storage facility now can no longer sell the same energy later or use it for grid support. The relevant marginal costs therefore depend on expected future prices, technical losses and other possible uses. The situation is similar for flexible demand, such as electrolysers, heat pumps with buffer storage or industrial processes. Low prices can create an incentive there for additional electricity consumption if consumption can technically be shifted.

The term is therefore closely linked to flexibility. The more electricity generation depends on the weather, the more important it becomes that consumption, storage and controllable generation respond to price signals and grid conditions. The finer 15-minute resolution in the day-ahead market is intended to reflect such fluctuations within an hour better. Marginal costs then determine not only which power plant runs. They also help decide whether electricity is stored, consumed, curtailed or replaced by another technology.

Marginal Cost, Scarcity and Security of Supply

In an electricity system with many plants with low marginal costs, market prices can remain low for a long time and rise very high in a few hours. High prices in scarcity situations do not merely reflect high fuel costs. They can indicate that available firm capacity is scarce or that flexible demand can only be reduced at high cost. Such price spikes are meant to create incentives for investment and operation, for example for storage, flexible loads, reserve power plants or renewable generation backed up by storage and control.

Whether these price signals are sufficient depends on market rules and the political framework. Price limits, capacity mechanisms, reserve requirements, congestion management and political interventions change the revenues and risks of plants. Marginal costs explain short-term dispatch, but do not automatically solve the long-term financing of capacity. Security of supply depends on whether enough plants, storage, grids and flexible consumers are available when they are needed.

A further distinction concerns grid congestion. In a single bidding zone, the exchange price behaves as if electricity were equally available everywhere within the zone. Physically, however, transport can be limited. Grid operators then have to reschedule power plants, curtail feed-in or use redispatch. The marginal costs of generation are then only part of the actual costs of system operation. Whether a cheap megawatt hour also arrives where it is needed depends on its geographical location, grid capacity and connection conditions.

Conclusion

Marginal costs precisely denote the short-term additional costs of a further quantity of electricity. They explain the dispatch order of many plants and a central mechanism of exchange price formation. However, they do not replace a full-cost calculation, investment analysis, grid planning or an assessment of security of supply. Anyone who wants to understand electricity prices, power plant dispatch or the effect of renewable energies should distinguish: is the question about the next megawatt hour, or about the costs of a permanently reliable electricity system?

Sources

EU electricity trading in the day-ahead markets becomes more dynamic — Europäische Kommission, GD Energie; 2025-10-01. Nachrichtenmeldung, gesamter Text
ACER Decision 02/2026 on the harmonised maximum and minimum clearing prices for single day-ahead coupling – Annex I — Agentur der Europäischen Union für die Zusammenarbeit der Energieregulierungsbehörden (ACER); 2026 (genaues Datum unbekannt). Annex I, Art. 3 und Art. 4
EWI Merit-Order-Analyse November 2022 — Energiewirtschaftliches Institut an der Universität zu Köln (EWI); 2022-11. Analyse zu Brennstoff- und CO₂-Preisen und Grenzkosten konventioneller Kraftwerke
Wissenschaftliche Dienste WD 5 - 3000 - 121/22 zur Strompreisbildung — Deutscher Bundestag, Wissenschaftliche Dienste; 2022 (genaues Datum unbekannt). Abschnitte zu Großhandelspreis, Grenzkraftwerk und Endverbraucherpreis
Die Gewinnmitnahmen deutscher Stromerzeuger in der zweiten Phase des EU-Emissionshandelssystems — Öko-Institut; 2008. Einleitende Abschnitte zu Grenzkosten und Einpreisung der CO₂-Kosten

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Edited by eCMS on 12.11.2026 05:05