How Electricity Prices Are Set: Day-Ahead, Real-Time, Imbalance

Wholesale electricity prices are set by matching sellers’ offers against buyers’ bids, first in an auction held the day before delivery and then in shorter-term markets that settle what actually happens on the grid. Europe leans on the day-ahead auction, Australia’s National Electricity Market prices every five minutes in real time, and Great Britain charges an imbalance price to anyone whose metered position differs from what they contracted.

All three answer the same problem: electricity is generated at the moment it is used, so a market needs a price for every short interval and a way to charge for the gap between plans and reality. That is why a Danish, an Australian and a British price on our pages do not mean quite the same thing.

The common principle: marginal pricing

Most wholesale markets use uniform marginal pricing. Generators offer quantities at prices, buyers bid for quantities, and the market stacks the offers from cheapest to most expensive until demand is met. The price of the last offer needed, the marginal unit, becomes the price paid to every accepted seller and by every accepted buyer in that zone and interval.

When wind and solar, which have almost no fuel cost, cover most of demand, the marginal unit is cheap and the price drops, sometimes below zero. When the last unit needed is a gas plant, its cost sets the price for everyone. When transmission between two areas is full, they stop sharing one marginal unit and their prices separate.

Day-ahead: Europe’s single auction

In most of Europe the main price is fixed the day before delivery through Single Day-Ahead Coupling, or SDAC. ENTSO-E describes its aim as creating “a single pan European cross zonal day-ahead electricity market”. Power exchanges collect orders from their members, and a shared algorithm called EUPHEMIA matches supply and demand for the whole of the next day across all participating bidding zones at once, taking the capacity of the cross-border lines into account.

The result is one price per bidding zone per market time unit. Until 2025 that unit was an hour. ENTSO-E records that SDAC moved from hourly to 15-minute market time units, with 30 September 2025 as the first trading day and 1 October 2025 as the first delivery day. A day now has 96 prices per zone rather than 24. The auction also has harmonised price limits; ENTSO-E’s information note sets the minimum clearing price at −600 EUR/MWh from trading date 28 May 2026.

Denmark is a clear example. Energinet publishes the results for the two Danish zones, DK1 and DK2, in its DayAheadPrices dataset on Energi Data Service, with each 15-minute interval stamped at its start in UTC and in Danish time, and with prices in both euros and Danish kroner per megawatt-hour. Because the auction clears before the delivery day begins, tomorrow’s Danish prices are known in advance. That is what makes it possible to list the cheapest hours for the next day.

A day-ahead price is a commitment made on forecasts. If the wind arrives late or a power station trips, the system is balanced through intraday trading and the transmission operator’s balancing markets. Our Danish pages show only the day-ahead result: an auction outcome, not a measurement of the grid at that minute.

Real-time: five-minute dispatch in Australia

Australia’s National Electricity Market works differently. It has no day-ahead auction for physical delivery. Instead the market operator, AEMO, runs a central dispatch: generators submit offers, AEMO dispatches the cheapest combination that meets demand while respecting network limits, and the resulting regional price for each five-minute interval is the spot price.

For many years dispatch ran every five minutes but money changed hands on a 30-minute basis. The AEMC made a rule on 28 November 2017 to change the settlement period for the spot price from 30 minutes to five minutes, saying the change would “align operational dispatch and financial settlement at five minutes”. Five-minute settlement began on 1 October 2021. Each NEM region (Queensland, New South Wales, Victoria, South Australia and Tasmania) has its own price, and the prices separate when interconnectors are constrained.

The NEM allows very wide prices. The AEMC set the market price cap for 1 July 2026 to 30 June 2027 at A$23,200/MWh, and its reliability report lists the market price floor at −A$1,000/MWh. Within those limits an Australian price can swing sharply inside one hour.

AEMO also publishes pre-dispatch, a rolling forecast of prices for the hours ahead based on current offers and forecast demand. It is a forecast and is revised as offers change. On our Australian cheapest-hours pages, hours still to come use AEMO’s pre-dispatch prices and are labelled “forecast by AEMO”; hours already past use the settled five-minute prices.

Imbalance: Great Britain’s single price

Great Britain sits between the two models. Generators and suppliers trade bilaterally and on exchanges up to shortly before each half-hour, and the system operator then balances the system by accepting offers and bids in the Balancing Mechanism. Elexon settles every participant’s metered volume against their contracted volume for each half-hour settlement period. A normal settlement day has 48 periods, and the long clock-change day in October has 50.

Anyone whose metered position does not match their contracts pays or receives the imbalance price for the difference. Ofgem describes imbalance prices as “the default price for uncontracted electricity” and “a primary incentive on participants to balance their positions”. Under modification P305, implemented on 5 November 2015, the arrangements moved to a single cash-out price for each settlement period. Before then, being short and being long could be priced differently. P305 also made the price more “marginal”, calculating it from the most expensive balancing actions the system operator takes.

Our Great Britain page shows two half-hourly prices for this reason. The imbalance price reflects the cost of balancing actions. The market index price reflects short-term trading for the same period. They often differ, and when the system is under stress the imbalance price can move much further.

Locational prices in U.S. organised markets

The organised markets in the United States add geography to the price. ISO New England defines a locational marginal price, or LMP, as “the price for electric energy” at each pricing location, built from three components: an energy component common to the system, a congestion component and a loss component. ISO New England reports more than 1,000 pricing nodes. Its day-ahead LMPs are calculated for each hour of the day-ahead market, and real-time LMPs are calculated every five minutes using actual system conditions.

We do not show U.S. prices; our U.S. pages carry delayed, preliminary hourly demand and generation from the EIA Hourly Electric Grid Monitor.

The four designs compared

Market	Main price	Interval	Fixed when	Shown on our pages
Denmark (SDAC)	Day-ahead auction price per bidding zone	15 minutes since delivery day 1 October 2025	The day before delivery	DK1 and DK2 day-ahead price
Australia (NEM)	Regional spot price from central dispatch	5 minutes, settled at 5 minutes since 1 October 2021	In real time	Dispatch price; AEMO pre-dispatch as forecast
Great Britain	Imbalance price, single since 5 November 2015	30-minute settlement periods	After the period	Imbalance price and market index price
U.S. organised markets	Locational marginal price	Hourly day-ahead; 5-minute real-time (ISO New England)	Day ahead and in real time	Not shown

What a household bill adds on top

A wholesale price is only one part of what a household pays. In Britain, Ofgem calculates its price cap from wholesale costs, network costs for “the pipes and wires”, policy costs for government schemes, supplier operating costs, an allowance for supplier earnings, headroom for uncertain costs, a levelisation allowance and VAT. The cap limits the unit rate and standing charge, not the total bill.

In Denmark, a household pays its local grid company’s network tariff, a subscription, taxes and VAT on top of the electricity itself. Grid companies such as N1 split the network tariff into low-load, high-load and peak periods, with the peak from 17:00 to 21:00. A cheap wholesale price in the early evening can therefore still be an expensive hour on the bill.

The wholesale price reaches a household directly only when its contract passes it through, as with a variable hourly tariff. On a fixed or capped tariff the wholesale price works in the background: it affects what suppliers pay and, over time, what they charge, but not the cost of a particular hour.

Reading the prices on this site

Every price on our pages is the operator’s published figure, badged Metered and stamped with the start of its interval in UTC. None is a forecast of our own, and all are provisional and may be revised by the operator.