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Glossary · Energy industry & energy transition

Day-ahead price

Day-ahead price Day-ahead market power exchange market clearing price pay-as-clear electricity market merit order spot market

The day-ahead price is the exchange price for electricity that is determined on the day before for delivery on the following day. It applies to precisely defined delivery periods. In the European Single Day-Ahead Coupling (SDAC), these periods were changed: the auction on trading day 30 September 2025 was the first to use quarter-hours instead of hours, starting with delivery day 1 October 2025. Since then, almost all coupled bidding zones have had a separate price for each quarter-hour. One exception is Ireland, with 30-minute periods. Older time series therefore contain hourly prices. Hourly values published today are generally averages of four quarter-hour prices. Anyone comparing time series across this point in time should take this into account.

The price is quoted in euros per megawatt-hour (€/MWh). One megawatt-hour equals 1,000 kilowatt-hours. A day-ahead price of 100 €/MWh therefore corresponds arithmetically to 10 cents per kilowatt-hour at the wholesale level. This does not yet include network charges, taxes, levies, duties, sales costs and the risk premiums of an electricity supply contract. For context: according to the market data of the Bundesnetzagentur, the average day-ahead wholesale price in Germany in 2025 was 89.32 €/MWh, i.e. just under 9 cents per kilowatt-hour.

How the price is formed

The price is formed in an auction on the day-ahead market. The coupled auction closes every day at 12:00 CET and applies to the entire following day. Power producers, traders, suppliers, direct marketers, storage operators and large consumers submit bids to buy and sell. Each bid states quantities and prices for individual delivery periods. A common algorithm brings together supply and demand from all coupled bidding zones. In doing so, it takes cross-border transmission capacities into account and maximises total welfare, i.e. the combined benefit to buyers and sellers. This yields a market clearing price for each delivery period and bidding zone.

In the European day-ahead auction, a uniform price applies under the pay-as-clear principle. All successful sellers in a bidding zone receive the same price for a delivery period, and all successful buyers pay it. In simplified terms, this is the price at which the supply and demand curves intersect, i.e. the price of the last bid still needed. For block bids and other complex bids, the calculation may deviate from this in individual cases. An example: if the most expensive power plant still needed costs 120 €/MWh, a wind turbine with almost zero marginal costs also receives 120 €/MWh in that quarter-hour. It is different with the pay-as-bid method. There, each successful bid would be settled at its own bid price.

The price is technically capped at the top and bottom. These harmonised maximum and minimum prices are regulated at European level and can shift automatically according to fixed rules. The maximum price was most recently +4,000 €/MWh. The minimum price was lowered from −500 to −600 €/MWh as of trading day 28 May 2026. Because these limits may change, the current status should be checked with the exchanges before use.

The day-ahead price is closely linked to the merit order. Here, offers are sorted by their short-term marginal costs, i.e. the cost of one additional megawatt-hour. Wind and photovoltaic plants have no fuel costs and therefore often bid very low. Sometimes they even bid at negative prices when support or marketing rules influence their dispatch decisions. Gas and hard coal power plants or other flexible generators usually bid at higher prices. For them, fuel costs, CO₂ costs, efficiencies and start-up costs play a role. The day-ahead price therefore does not show the average cost of the entire electricity system. It shows the price of the last unit still needed to meet expected demand in a delivery period.

Distinction from other electricity prices

The day-ahead price is a wholesale price. It is not the same price that households or smaller businesses see on their bills. End-customer prices additionally include network charges, metering operation, electricity tax, concession fee, value-added tax, the supplier's procurement costs, sales costs and risk margins. In addition, suppliers usually buy electricity through a mix of the forward market, day-ahead market, intraday market and their own generation. The day-ahead price can therefore fluctuate strongly, while a household contract has a fixed energy price for months or years. An exception is dynamic electricity tariffs. They pass day-ahead prices directly on to customers, supplemented by the other price components.

The day-ahead market differs from the forward market in the time gap to delivery. On the forward market, electricity is traded weeks, months or years before delivery, mainly to hedge against price risks. The day-ahead market is closer to the delivery date. It processes more up-to-date information on weather, demand, power plant availability and cross-border trading capacities. The intraday market operates on an even shorter timescale. There, deviations that only become known after the day-ahead auction are traded, for example due to changed wind forecasts, power plant outages or changes in consumption.

Balancing energy is also something different from the day-ahead price. Transmission system operators procure balancing energy to offset deviations in grid frequency during ongoing operation. It serves system security, not normal electricity procurement. The day-ahead market produces schedules for the balancing groups. Balancing energy is used when actual feed-in and withdrawal do not match despite these schedules. A high day-ahead price therefore indicates expected scarcity or high marginal costs in a delivery period. Balancing energy prices, by contrast, arise from short-term balancing needs and technical reserve requirements.

Why the day-ahead price matters in the electricity system

The day-ahead price aligns the expectations of market participants. It condenses information on weather, load, power plant availability, fuel and CO₂ prices, storage levels and grid capacities into one price signal for the next day. This determines which power plants are scheduled, whether storage units charge or discharge, whether flexible consumers shift their demand and how direct marketers value renewable electricity. For many market participants it is a reference price, even if they do not buy every kilowatt-hour directly in the auction. The Bundesnetzagentur points out that wholesale prices are essentially formed on the day-ahead market.

For operators of renewable plants, the day-ahead price is particularly important because it often forms the basis of revenues in direct marketing. Wind and solar plants generate electricity depending on the weather. Their output can only be forecast the day before, not reliably planned. Forecast errors are later balanced out through intraday trading or as balancing group deviations. The day-ahead price thus values the expected feed-in but does not guarantee the actual value of each kilowatt-hour generated. When many solar plants produce at the same time, prices can fall sharply or turn negative at midday. When wind and solar output is low and demand is high, they can rise significantly. Thanks to the quarter-hour resolution, such fluctuations within an hour are now shown more precisely.

Storage also responds to the day-ahead price, provided it trades on the electricity market. A battery can charge at low prices and discharge at higher prices. For profitability, however, the price difference is not the only factor. Efficiency losses, ageing, network charges, rules on levies, marketing costs and possible additional revenues in other markets are also important. The day-ahead price thus shows an opportunity to earn from price differences. But it does not by itself explain whether a storage project is worthwhile. Dedicated bid types for storage are being developed for the European auction. According to ENTSO-E, their introduction is currently planned for the fourth quarter of 2027.

Common misunderstandings

A common misunderstanding is to treat the day-ahead price as "the electricity price". For analyses of the wholesale market it is central, but for end-customer costs it is only one building block. Falling exchange prices do not automatically lower household electricity prices. This applies, for example, if network charges rise, if the electricity was already purchased long-term, or if taxes and levies stay the same. Conversely, high day-ahead prices do not mean that all consumers are supplied at this price. Many volumes are hedged through forward contracts, fixed-price contracts or their own procurement strategies.

A second misunderstanding concerns negative prices. They do not mean that electricity is "worthless". They arise when more electricity is offered in a delivery period than buyers willing to pay want to take, and suppliers prefer to pay for offtake rather than curtail their generation. Reasons can include technical minimum output of conventional power plants, support rules, heat extraction, inflexible demand or grid congestion that is not reflected within the price zone. Negative prices therefore often show that the system adapts poorly, and not simply a physical surplus. Negative prices are also limited, by the harmonised minimum price mentioned above.

A third misunderstanding is to equate the day-ahead price with generation costs. The market clearing price reflects the short-term marginal situation. It says nothing complete about investment costs, grid expansion, reserve provision, system services or political risks. An electricity system can have many hours with low day-ahead prices and still incur high total costs if capacities, grids, flexibility and hedging are expensive. Conversely, high prices in individual hours can bring important revenues for flexible power plants, storage or controllable consumers that are only rarely deployed.

Bidding zone, grid and European coupling

The day-ahead price is determined for bidding zones. Germany and Luxembourg currently form a common bidding zone. Within a bidding zone, the market assumes for simplicity that electricity can be traded without congestion. Physically, however, the grid has bottlenecks. If lines would be overloaded after the auction, grid operators intervene through redispatch. In this process, power plants are ramped up at one location and ramped down at another so that grid limits are respected. These costs are not contained in the day-ahead price of the bidding zone. They are distributed through network charges and regulatory procedures.

Between bidding zones, market coupling incorporates the available transmission capacities. The algorithm allocates the scarce cross-border capacities so that total benefit is greatest. In most cases, electricity flows economically from zones with lower prices to zones with higher prices. This causes prices to converge in part. When cross-border capacities are exhausted, price differences remain. In regions with flow-based capacity calculation, individual trade flows can also run against the price direction if this increases total benefit. A price in Germany therefore does not depend only on German generation and demand. It can be influenced, for example, by wind in Denmark, the availability of French nuclear power plants, hydropower in Scandinavia, European gas prices or bottlenecks at borders.

What the term shows and what it does not

The day-ahead price shows how the market values the expected scarcity of a particular delivery period. It shows when flexible demand can be valuable, when storage can earn revenues, when renewable electricity lowers the wholesale price and when thermal power plants set the price. It is thus an important signal for operation, marketing and short-term planning.

It does not, however, explain security of supply on its own. Low prices in many hours say little about whether enough firm capacity is available during a rare Dunkelflaute (prolonged period of low wind and solar output). A high price in one hour does not automatically mean that a supply outage is imminent. Security of supply depends on capacities, reserves, grid stability, fuel availability, balancing group discipline and regulatory powers to intervene. The day-ahead price touches on these questions but does not replace an analysis of capacity, flexibility, residual load and grid operation.

In political debates, the term is useful when its limits are openly stated. Anyone talking about low exchange prices should say whether this concerns individual quarter-hours or hours, monthly averages, annual averages or the volume-weighted revenues of specific plants. Solar power often achieves a different average market value than a power plant delivering evenly. The reason: many solar plants produce at the same time and thereby depress their own revenues. Wind power, storage, flexible industrial processes and steady baseload consumption each have different price profiles. Average prices obscure these differences.

The day-ahead price thus describes precisely the short-term wholesale value of electricity on the day before delivery. It is a central price signal for trading and operation, but not a complete measure of end-customer costs, investment needs or security of supply. What it indicates depends on the delivery period, the bidding zone, the pricing rule, the expected feed-in and demand. Anyone using it should therefore always state which market stage, which time resolution and which bidding zone is meant.

Sources

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Edited by eCMS on 11.11.2026 18:36

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