Day-ahead market · Glossary

The day-ahead market is the organised electricity market in which electrical energy is traded for the following delivery day. Market participants submit buy and sell bids for individual delivery periods or for standardised blocks. From all bids, a single auction calculates prices and volumes for each delivery period. In this way, expected generation, expected consumption and cross-border trading opportunities become binding trading positions for the next day. In Europe, the smallest delivery period, the Market Time Unit (MTU), has been the quarter-hour since delivery day 1 October 2025. Before that, it was the hour.

What is traded is energy, not power in the technical sense. The volume is stated in megawatt-hours (MWh), the price in euros per megawatt-hour. Anyone who delivers a constant 100 megawatts over a full hour delivers 100 MWh. In a single quarter-hour, the same power amounts to only 25 MWh. Power therefore describes the instantaneous feed-in or offtake, while energy is the quantity delivered over the period. This distinction matters for the day-ahead market: the market assigns energy volumes to each delivery period. Grid operation and system security, by contrast, must additionally take into account the simultaneous power balance, grid loads and reserves. The day-ahead price is therefore a price for electrical energy in a specific delivery period. It is not a complete price for firm capacity or grid stability.

European market coupling and the course of the auction

In the EU and in some other countries, day-ahead trading is organised as a coupled auction, known as Single Day-Ahead Coupling (SDAC). Power exchanges, referred to in EU law as nominated electricity market operators (NEMOs), and transmission system operators calculate the result jointly using a single algorithm. This algorithm simultaneously takes into account all bids and the available cross-border transmission capacities. The aim is to maximise overall economic benefit, known as welfare, and to use scarce interconnection capacity as efficiently as possible.

Bids are accepted until the gate closure time of 12:00 Central European Time on the previous day. The algorithm then runs and the results are published. Since trading day 30 September 2025, prices in all SDAC bidding zones and at all zone borders have been determined at 15-minute resolution. According to EPEX SPOT, Ireland remains with 30-minute units. Hourly products and block bids remain possible: an hourly bid is then applied to the four quarter-hours of the hour. Switzerland is not part of EU market coupling. According to EPEX SPOT, its own day-ahead auction likewise switched to quarter-hours in November 2026.

In coupled markets, traded volumes flow from lower-priced zones to higher-priced zones as long as sufficient transmission capacity is available. If the capacity is insufficient, the prices of the zones diverge. They then remain as far apart as the congestion forces. The result of each bidding zone is therefore closely linked to that of its neighbours. A windy day in northern Germany, for example, can also push down prices in neighbouring countries.

Bids and price formation

Price formation essentially follows the merit order. Sell bids are sorted by ascending price, buy bids by descending price. Where the supply and demand curves intersect, the market clearing price arises. Plants with low short-term marginal costs are often far ahead in the order, for example wind power, photovoltaics or running nuclear power plants in countries that still operate them. Gas- and coal-fired power plants or storage units bid at higher prices depending on fuel and CO₂ costs, efficiency, start-up costs and opportunity costs. For storage, these are primarily the expected revenues in other hours. Within a bidding zone, in principle all accepted bids receive the same price, even if individual plants bid lower (uniform-price method, in English pay-as-cleared). With block bids and other complex bids, a bid can be rejected despite an apparently matching price. The reason is that blocks are accepted only in full or not at all.

This uniform price is often misunderstood. It does not mean that every power plant has its full costs recovered in every quarter-hour. Nor does it mean that the most expensive generator “sets” the price politically. The price is the result of an auction rule that ranks scarce generation and consumption options for a specific delivery period. Through the bids, fuel prices, CO₂ costs, weather forecasts, technical availability and demand expectations influence the result. Long-term investment costs appear only indirectly, for example via expected revenues or risk premiums. Strategic behaviour is permissible only within the rules against market abuse.

Prices are technically capped upwards and downwards. These harmonised maximum and minimum prices are based on a methodology under Article 41 of the CACM Regulation, which ACER most recently amended with Decision No 02/2026 of 4 February 2026. The reference values are +4000 euros/MWh at the upper end and −500 euros/MWh at the lower end. If prices rise or fall close to these limits, an automatic mechanism adjusts them. Since delivery day 29 May 2026, the lower limit has been −600 euros/MWh, while the upper limit remains unchanged at +4000 euros/MWh. Because the limits can adjust automatically, the current status should be checked with the exchanges before use.

Distinction from the forward market, the intraday market and balancing energy

On the forward market, suppliers, generators and large consumers hedge electricity volumes weeks, months, quarters or years in advance. This serves primarily risk management. The day-ahead market, by contrast, fixes the concrete delivery for the next day. Its result is also the most important reference price for many forward contracts and supply contracts.

It differs from the intraday market in timing and function. After the auction, forecasts change: wind farms feed in differently than expected, cloud cover shifts photovoltaic generation, power plants fail or consumption profiles deviate. On the intraday market, market participants can adjust their positions until shortly before delivery. It corrects forecast errors but does not replace the coordinating effect of the day-ahead auction.

Balancing energy is a separate layer. Transmission system operators use it to offset remaining deviations between generation and consumption in real time and to keep the grid frequency stable. The day-ahead market produces schedules and trading positions. Balancing energy deals with unplanned deviations in actual operation. Anyone who reads the day-ahead price as a price for security of supply conflates market coordination with system services.

Schedules, balancing groups and grid operation

The market result consists not only of prices. It also fixes trading positions from which schedules arise. Suppliers, traders, direct marketers, storage operators and large consumers map their feed-ins, offtakes and transactions in a balancing group. This is a computational account that is supposed to be balanced in every settlement period. If the actual volumes deviate from the notified schedules, the balance responsible parties bear the financial risk via imbalance energy prices.

For grid operators, these schedules are an important information basis. Within a bidding zone, however, the day-ahead market does not reflect grid congestion. Germany and Luxembourg form a joint bidding zone, even though wind power is generated mainly in the north and a great deal of electricity is consumed in the south. The European bidding zone review had recommended in 2025 a split into up to five zones. In December 2025, with its “Action Plan Bidding Zone” (Aktionsplan Gebotszone), the Federal Ministry for Economic Affairs decided to retain the single zone. A change cannot in any case be decided by Germany alone at national level. If the market result would overload lines, grid operators intervene with redispatch: plants are ramped up or down in deviation from the market result.

This separation of market and grid is institutionally intended but generates costs and distributional effects. A low day-ahead price does not mean that delivery is possible at every location without additional costs. Costs for redispatch, reserve provision and system services are not included in the exchange price. They are paid for to a large extent via grid charges.

Renewable feed-in, negative prices and flexibility

With a growing share of wind and photovoltaics, the role of the day-ahead market changes. Weather-dependent plants have very low marginal costs but fluctuating availability. When a lot of wind and sun are forecast, supply shifts towards low prices. With high demand and little renewable feed-in, more expensive flexible plants are needed and prices rise. The 15-minute resolution additionally makes short-term ramps visible, for example in the morning and evening, when solar generation rises or falls.

Negative prices arise when more generation is offered in a delivery period than is demanded at positive prices, and not enough flexibility is available. Reasons can include minimum outputs of conventional power plants, heat-led combined heat and power, support rules that create incentives to feed in despite low prices, lack of storage, inert demand or limited export possibilities. Negative prices do not mean that electricity would be physically worthless. They show that at that moment the ability to absorb electricity, shift it or curtail generation is scarce.

As a result, flexibility gains economic value. Battery storage charges at low prices and discharges at high prices. Heat pumps, electrolysers, charging points for electric cars and industrial processes can shift their consumption if technology, comfort requirements, tariffs and market rules allow it. The price signal alone, however, does not create flexibility. This requires metering, controllability, suitable tariffs, aggregators, appropriate balancing rules and investment in plants and IT.

What the day-ahead price shows and what it obscures

The day-ahead price is one of the most important reference prices in the electricity system. It influences direct marketing, procurement strategies, storage revenues and political debates about electricity costs. Grid charges, taxes, levies, sales costs, long-term hedging, and reserve and redispatch costs are not included in it, however. Household and industrial electricity prices therefore cannot be explained by the day-ahead price alone.

A further oversimplification arises when the market result is understood as a direct image of the electricity mix of a quarter-hour. The auction assigns traded volumes within bidding zones. Physical electricity, by contrast, follows the laws of electrical engineering and the structure of the grid, not contracts. Trading flows, physical flows and guarantees of origin allocated on an accounting basis are different levels. Anyone who mixes them up confuses price formation, climate accounting and grid operation.

The day-ahead market also provides no complete picture for investments. Frequent price spikes can make flexible generation, storage and load shifting more attractive. Frequent low or negative prices can reduce the revenues of plants that feed in heavily in the same hours. Whether investment actually takes place also depends on expected volatility, financing costs, regulatory risks, grid connection conditions and further revenue sources. The day-ahead market sends a signal but does not guarantee sufficient firm capacity.

The day-ahead market is thus the central auction layer for the short-term economic coordination of the electricity system. It makes expected scarcities for the next day visible, creates binding trading positions and provides a price signal for generation, consumption and flexibility. Its explanatory power ends where grid constraints, real-time deviations, system services and long-term investment risks begin.

Sources

15-minute products in Market Coupling — EPEX SPOT; unbekannt (Inhalt mit Stand November 2026). Abschnitt Introduction of 15-minute MTU contracts for Day-Ahead – SDAC
Successful Implementation of 15-Minute Market Time Unit (MTU) in SDAC — EPEX SPOT / SDAC-Parteien; 2025-10-07. Pressemitteilung, Abschnitt About SDAC
ACER Decision No 02/2026 on the harmonised maximum and minimum clearing price methodology for SDAC — Agentur der Europäischen Union für die Zusammenarbeit der Energieregulierungsbehörden (ACER); 2026-02-04. Erwägungsgründe sowie Anhang Artikel 3 (die Werte sind in der von OMIE veröffentlichten Fassung derselben Entscheidung belegt)
New Harmonized Minimum Clearing Prices for Nordic currencies starting from the 28th May 2026 (Trading Date) — Nord Pool; 2026-05-08. Operational Message
Politik: Regierung hält an einer deutschen Strompreiszone fest — Energie & Management; 2025-12 (genaues Datum unbekannt). Nachrichtenartikel zum Aktionsplan Gebotszone des BMWE

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Edited by eCMS on 11.11.2026 18:35