Flow-Based Capacity Calculation · Glossary

Flow-Based Capacity Calculation is a method for calculating cross-border transmission capacities in the European electricity market. In German it is usually called "flussbasierte Kapazitätsberechnung". The method does not simply fix how much electricity may be traded between two countries. It calculates how trading positions between bidding zones are expected to affect individual lines and transformers in the transmission grid. It is thus a specific form of capacity calculation and the basis of flow-based market coupling.

The method responds to a property of the meshed alternating current grid: electricity does not follow the trading contract. If electricity is sold in one bidding zone and bought in another, the physical flow is distributed across many parallel paths according to the electrical properties of the grid. What matters above all is the impedance of the lines, which in the extra-high-voltage grid is essentially their reactance. Ohmic resistance alone is not sufficient as an explanation. A trade between Germany and France can therefore also load lines in Belgium, the Netherlands or Austria. Flow-based calculation takes such loop flows and transit flows into account before the market is cleared.

What is calculated in flow-based calculation

The focus is not on national borders but on critical network elements under specific outage assumptions. These are called CNECs (Critical Network Element and Contingency). They are overhead lines, cables or transformers that are relevant for cross-border trade. Each is considered together with an N-1 outage, i.e. the outage of another piece of equipment. In the Core region, these elements are defined separately for both flow directions. In addition, there are monitored-only elements (MNEC). They must not exceed a threshold, but they do not directly limit the capacity space.

For each of these elements, the calculation determines how strongly a change in the net positions of the bidding zones changes its loading. Power Transfer Distribution Factors (PTDF) are used for this. A PTDF indicates what share of a change in a net position appears as additional flow on a network element. An example: with a zone-to-zone PTDF of 0.2, 100 MW of additional exchange between two zones leads to about 20 MW more flow on the line concerned. So that zonal values can be transferred to individual power plants and loads in the grid model, the grid operators use so-called Generation and Load Shift Keys (GLSK). These are assumptions about which generation and consumption units bear a change in the net position. In the Core region, only elements whose largest zone-to-zone PTDF is at least 5 percent remain in the data set. Elements that barely react to trade should not limit trade.

The Remaining Available Margin (RAM), in megawatts, indicates how much room for trade remains on an element. In simplified terms, one starts from the maximum permissible loading Fmax. From this one deducts a reliability margin for forecast errors and the expected flow without cross-border trade. Further corrections may be added where applicable. An adjustment for minimum capacity (AMR) can increase the margin. Validation reductions by the grid operators can decrease it, but not below 0 MW. The market algorithm therefore does not receive a fixed value such as 1,000 MW between country A and country B. It receives a set of inequalities, the so-called flow-based domain. A combination of net positions is feasible if, on none of the relevant elements, the sum of PTDF times net position exceeds the RAM. Capacity is thus not a single limit value but a multidimensional capacity space.

Process using the Core region as an example

In the Core capacity calculation region, the day-ahead calculation begins in the afternoon two days before delivery (D-2). It ends on the previous day at 10:00, when the flow-based domain is handed over to market coupling. The process has four steps:

Input data: Each grid operator supplies, for every hour, a forecast of its grid two days ahead. It contains generation, load, topology and planned outages. In addition there are GLSKs, CNEC lists and possible cost-free measures. From this a common grid model (Common Grid Model) is created.
Calculation: First, PTDFs and RAMs are determined. Then cost-free measures, such as switching actions or the tap position of phase-shifting transformers, are optimised in order to increase the smallest relative margin. Subsequently, the minimum capacity is taken into account.
Validation: The grid operators check whether grid security is maintained. If necessary, they reduce the margin of individual elements. An increase is not permitted in this step.
Finalisation: Capacities allocated in the long term and nominations are taken into account. The result is published and handed over to day-ahead coupling.

Distinction from NTC and ATC

Flow-Based Capacity Calculation is often explained in contrast to NTC and ATC methods. NTC stands for Net Transfer Capacity, i.e. a net transmission capacity per border and direction between two market areas. ATC stands for Available Transfer Capacity, i.e. the quantity still available after deducting capacity already allocated. Both quantities express capacity along bilateral borders and are therefore easier to understand.

This simplicity comes at a price. In a meshed grid, a bilateral figure only roughly reflects which lines a trade actually uses. The grid operators have to allocate the mutual influence of borders in advance on a flat-rate basis. If the values are too cautious, usable capacity remains unused. If they are too generous, the need for subsequent congestion management increases. The flow-based method does not reproduce the grid perfectly, because it is based on a linearised model and on forecasts. However, it brings the physical effect of trade flows considerably closer to market coupling.

Commercial and technical capacity must be distinguished. A line has a thermal loading limit and must meet stability and security requirements. The capacity offered to the market is derived from this, but is not identical to it. It additionally depends on forecasts, safety margins, load shift keys, regulatory minimum values and validation decisions.

Areas of application and status

Under the European guideline CACM, flow-based calculation is considered the target method in the day-ahead and intraday timeframes where capacities between bidding zones are strongly interdependent. In Central Western Europe (CWE) it has been used since 2015. On 8 June 2022 (first delivery on 9 June) it was extended to the entire Core region within the day-ahead market coupling SDAC. On 29 October 2024, the Nordic region followed with Denmark, Finland, Norway and Sweden.

In the intraday timeframe, too, the Core region was converted step by step: in 2024 the IDCC(a) and IDCC(b) calculations were added, in 2025 IDCC(c) and in April 2026 IDCC(d). With IDCC(e), in operation since 14 October 2026, the planned sequence is complete. In intraday trading SIDC, capacity is calculated on a flow-based basis. For trading, however, ATC values are in part still derived from it.

Significance for market coupling and price formation

In the coupled day-ahead auction, bids from all bidding zones are matched together. The algorithm maximises welfare and must respect the flow-based domain as a constraint. Capacity calculation therefore directly co-determines how often prices diverge between zones. If a critical element has only little margin, it can restrict trade between several zones at the same time, even if no single border appears to be an obvious bottleneck. Conversely, the method permits trading combinations that flat-rate limit values would exclude. Because the algorithm optimises welfare across the whole area, so-called non-intuitive exchanges can occur in individual hours, i.e. exports from a more expensive to a cheaper zone.

The modelled availability of the grid thus becomes part of price formation. Price differences between bidding zones reflect not only generation costs and demand. They also show how capacity is calculated, secured and made available to the market.

Minimum capacity: the 70 percent rule

Within a bidding zone, trade is treated as congestion-free in market clearing. Internal congestion must be resolved by the grid operators after the market, for example through redispatch or countertrading. If internal flows occupy a lot of line capacity, less remains for cross-border trade. Article 16(8) of the EU Electricity Market Regulation (EU) 2019/943 therefore prescribes minimum values. For flow-based borders, at least 70 percent of the capacity of the internal and cross-border critical elements, taking contingencies into account, must be available for cross-border flows. Up to 30 percent may therefore be attributed to reliability margins, loop flows and internal flows. The 70 percent is a lower limit, not a target value.

The regulation allows transitional rules: national action plans with a linear trajectory, as well as time-limited derogations. Under the action plan rules, the minimum values are to be met from 1 January 2026. In the Core region, the minimum capacity adjustment converts two requirements into MW per element: 20 percent of Fmax for exchanges within Core and 70 percent of Fmax for all cross-border exchanges. The debate about these values shows that it is not only a matter of technology. It is also about how costs, risks and obligations are distributed among grid operators, Member States, market participants and regulatory authorities. Higher minimum margins can make more redispatch necessary.

Typical misunderstandings

More trade in every hour: The method is meant to make existing grid capacity usable more efficiently. However, it can also limit certain trading directions more strongly than an NTC value if they load critical elements heavily. More physical accuracy does not mean more cross-border trade in every hour.
Lack of transparency: The criticism has a factual core, because the results depend on grid models, forecasts, GLSKs and the selection of elements. However, a single figure per border would not automatically be more transparent from a technical standpoint if it merely conceals the physical effects. Transparency here means above all that assumptions, data and rules are traceable. The results of the Core region are therefore published daily on a platform.
Cause of congestion: The method does not create congestion. Congestion arises from grid structure, the spatial distribution of generation and consumption, outages, maintenance and security requirements. The calculation merely determines how these limits are taken into account before trading.

Why the term matters for the electricity system

With the growing share of fluctuating generation, load flows fluctuate more strongly in space and time. Wind power from the north, photovoltaic peaks at midday, storage, flexible consumers and the availability of power plants change the loading of the transmission grid from hour to hour. A method that reflects these interactions only roughly via national borders is poorly suited to such strongly changing patterns.

Flow-based calculation can help to make better use of the existing grid. However, it replaces neither grid expansion nor a sensible delimitation of bidding zones nor flexibility in generation and consumption. In the case of persistent structural congestion, a more precise method reflects the market consequences better, but the physical cause remains. Because the method is based on D-2 forecasts, the real grid situation may deviate. Reliability margins and intraday recalculations reduce this uncertainty, but they cannot eliminate it.

Flow-Based Capacity Calculation is thus an interface between physics, market rules and grid operation. European electricity trading depends not only on exchange bids. It also depends on which grid limits are modelled before trading, which margins apply and which congestion is only resolved afterwards in operation. The method is neither a synonym for free electricity trading nor a substitute for grid planning. It translates the limited transport capability of a meshed alternating current grid into European market coupling.

Sources

Verordnung (EU) 2019/943 über den Elektrizitätsbinnenmarkt (konsolidierte Fassung) — Europäische Union, EUR-Lex; 2022-06-23 (konsolidierte Fassung). Art. 15 und Art. 16 Abs. 8 Buchst. b
Core CCR Day-ahead process explained — ENTSO-E; unbekannt. Abschnitte Flow-based capacity calculation, Schritte 1–4
Core FB DA MC — JAO – Joint Allocation Office; unbekannt. Projektseite Core Flow-Based Market Coupling
Flow-Based Methodology successfully implemented in the Nordic Region (SDAC-Pressemitteilung) — SDAC / Market Coupling Steering Committee (veröffentlicht durch TGE); 2024-11-04. Pressemitteilung, Haupttext
Core intraday flow-based capacity calculation — ENTSO-E; unbekannt. Introduction

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Edited by eCMS on 12.11.2026 05:05