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The Nordic power market: how the power price is set

The Norwegian power price is set anew every day in a joint European auction. Here is how the price is formed, why it differs between regions, and how water, cables and gas prices connect to it.

Updated · about 8 min read · Written by OESA

The day-ahead auction: how the price is set

Most power in the Nordics is traded the day before it is used, in the day-ahead market. Producers, suppliers and large consumers submit bids to the power exchanges by 12:00 the day before delivery, stating how much they will sell or buy at each price. Since 1 October 2025 there has been a price for every quarter-hour, 96 prices a day; before that there was one price per hour (Nord Pool). Bids from much of Europe are pooled in one calculation, Single Day-Ahead Coupling (SDAC), which finds the prices in all areas and the flows between them at the same time.

The price is set by marginal pricing: everyone who sells gets the same price, and it is the cost of the last and most expensive unit needed that sets it (Energifakta Norge). Wind, solar and run-of-river hydro cost almost nothing to run and bid low. A gas-fired plant has to cover gas and CO₂ allowances and bids higher. Bids can range from −500 to 4,000 euros per MWh, so the price can turn negative (Nord Pool product specifications, 13 Jan 2026).

Prices are quoted in euros per MWh and published on Nord Pool's data portal. To get øre (hundredths of a krone) per kWh, multiply by the NOK/EUR exchange rate and divide by 10. After the auction, participants can trade to stay in balance in the intraday market until one hour before delivery, and Statnett handles any remaining imbalance in the balancing markets (Energifakta Norge).

The price areas NO1–NO5

Norway is divided into five bidding zones, often called price areas: NO1 Eastern Norway, NO2 Southwest Norway, NO3 Central Norway, NO4 Northern Norway and NO5 Western Norway. Sweden has four, Denmark two and Finland one. The borders run where the grid has large and lasting bottlenecks (statnett.no, read 5 Oct 2026). If there is enough capacity between two areas, the price is the same. If the line is full, the area with a deficit gets a higher price and the area with a surplus a lower one.

Nord Pool also calculates a system price for Norway, Sweden, Denmark and Finland as if there were no bottlenecks. Nobody trades power at the system price, but it is the reference in the futures market.

Hypothetical example. The numbers are chosen to show the method and are not market prices.

Area A uses 2,000 MW and has 4,000 MW of hydropower at 30 euros per MWh. Area B uses 5,000 MW and has 2,000 MW of wind power at 0 euros and 4,000 MW of gas power at 90 euros.

Without a bottleneck, wind and hydro cover 6,000 of the 7,000 MW, and gas supplies the last 1,000 MW. The price is 90 euros in both areas, as the system price shows.

With a 1,000 MW line, A can export only 1,000 MW. Hydropower is then the most expensive unit needed in A, so the price there is 30 euros, while B still needs gas and pays 90 euros.

The congestion income is 1,000 MW × (90 − 30) euros = 60,000 euros per hour, and Statnett uses its share to keep grid tariffs down. Without the bottleneck the price in A would have been 90 euros, so cables can raise the price in a surplus area.

Since 30 October 2024 capacity between the Nordic areas has been determined by flow-based market coupling, which treats the grid as a whole; Statnett's tests showed smaller price differences (Statnett, 1 Nov 2024). The zones can also change: Statnett has asked the Norwegian Energy Regulatory Authority (RME) to consider splitting NO4 in two (Statnett, 10 Dec 2025).

Hydropower and reservoir levels

Hydropower accounts for about 88 per cent of electricity production in a normal year. Norway has around 1,100 reservoirs and half of Europe's reservoir capacity, and more than 75 per cent of production capacity can be regulated as needed (Energifakta Norge, read 5 Oct 2026).

Inflow, the water running into the reservoirs, is largest during the spring snowmelt and low in winter, when consumption peaks. The reservoirs move water from summer to winter and from wet years to dry ones. Inflow can vary by 70–80 TWh between wet and dry years (Statnett, 1 Sep 2025).

A producer with a reservoir must always choose between producing now and saving the water, based on the price now and the price it expects later. What the water is worth if saved is called the water value, and it steers the bids from reservoir plants. Low reservoirs mean a high water value and high prices.

The Norwegian Water Resources and Energy Directorate (NVE) publishes reservoir statistics every Wednesday at 13:00. They show the fill level, the energy in the reservoirs as a share of the energy when they are full, for the whole country and each bidding zone, measured in the 489 most important reservoirs. Reservoir capacity was calculated at 87.4 TWh as of September 2025 (NVE).

Cables abroad and prices in Europe

Norway is connected to its neighbours by lines and subsea cables. The lines to Sweden run from Eastern, Central and Northern Norway, and in the north there is also a link to Finland. The subsea cables all run from southern Norway (Statnett). Total exchange capacity with other countries is about 9,000 MW (Energifakta Norge).

Subsea cables from southern NorwayStatnett, “Mellomlandsforbindelsene”, last updated 8 Jan 2025 (in Norwegian).
LinkToIn operation fromCapacity
Skagerak 1–4Denmark1976/77, 1994 and 2014500 + 500 + 700 MW
NorNedNetherlands2008700 MW
NordLinkGermany20211,400 MW
North Sea LinkUnited Kingdom20221,400 MW

Power flows from low to high prices. When it is windy and sunny on the Continent, Norway can import cheap power and save water; when there is little wind and sun, Norway exports. In 2025 Norway exported 34.3 TWh and imported 11.5 TWh (Energifakta Norge). Because most cables run from southern Norway, prices there are influenced more by European prices than prices in Central and Northern Norway are (Statnett).

This is how gas and CO₂ prices spill over. When a gas-fired plant is the most expensive unit needed in an area on the Continent, it sets the price there. Its cost per MWh of power is roughly the gas price divided by the plant's efficiency, plus the CO₂ price times the emissions per MWh. If the gas price (see TTF) or the allowance price rises, prices in Europe rise, and as long as the cables have spare capacity, prices in southern Norway are pulled along (Energifakta Norge).

The futures market and power contracts

The day-ahead price swings a lot. Producers, industry and suppliers therefore hedge future prices with financial contracts (futures and forwards). They are traded on exchanges or bilaterally and settled in cash, without delivery of power: the buyer receives the difference if the market price ends up above the contract price and pays it if the price ends up below (Statnett, Kraftmarkedsåret 2024).

The standard contracts are based on the system price, but a producer in NO4 is paid the NO4 area price. The gap can be hedged with an EPAD (Electricity Price Area Differential), a contract on the difference between the area price and the system price; together the two contracts give a full hedge for one area (same source). Nasdaq's Nordic power futures have moved to Euronext Nord Pool Power Futures, which was fully operational from 16 March 2026 (Euronext, 19 Mar 2026). EEX also lists futures on the system price and on each of the twelve Nordic bidding zones.

Households can choose a spot price contract, where the price follows the area price plus a mark-up, a fixed-price contract or a contract with a variable price (Energifakta Norge). From 1 October 2025 they can instead choose Norgespris, a fixed price from the state of 40 øre per kWh excluding VAT until 31 December 2026; other households receive electricity support when spot prices are high (regjeringen.no, updated 12 Feb 2026, in Norwegian). Grid tariffs and taxes come on top.

Power and the shelf

The shelf and the power market are linked in two ways.

  • Gas. Norwegian gas is a large part of Europe's gas supply, and the gas price affects power prices there and so prices in southern Norway. See the guide to gas to Europe.
  • Power from shore. When a field gets power from shore instead of its own gas turbines, consumption rises in the bidding zone where it is connected. For the operator it is a calculation: the turbines burn gas that could otherwise be sold, and the emissions cost CO₂ tax and allowances, while power from shore costs the power price, grid tariffs and the investment in cables. See power from shore in the energy transition guide.

Statnett points to new industry, data centres and electrification to meet climate targets as strong drivers of rising power consumption in Norway, while production looks set to grow little in the next few years (Statnett, 1 Sep 2025). Electrification of the shelf is therefore part of a wider debate about where power should be used, what the grid can handle and what it means for prices.

Sources

The guides are written by OESA students to explain concepts and how things fit together. They are not investment advice. Figures that are not definitions carry a source and a date; if you find an error, let us know at philipstave@oesa-global.com.

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