Frequency Control · Glossary

Frequency control refers to the technical, operational and market-based measures used to keep the grid frequency of an alternating current system close to its setpoint. In the Continental European interconnected grid, this nominal value is 50 hertz. The frequency indicates whether generation and consumption are in balance at every moment. If more electrical power is drawn than is fed in, the frequency falls. If more is fed in than is consumed, it rises.

The unit hertz indicates oscillations per second. At 50 hertz, voltage and current go through 50 complete periods per second. Since each period has two zero crossings, the polarity changes 100 times per second, not 50 times as is often stated. For individual consumers this figure usually remains invisible, but for grid operation it is a key control variable. Unlike voltage, frequency in a synchronously interconnected grid is largely a common system variable. European law therefore assumes that measurements across the entire synchronous area yield almost the same value within seconds. A disturbance in one part of the interconnection therefore does not only act locally, but changes the balance of the entire synchronously coupled system.

Frequency control is not mere fine-tuning. Larger deviations can trigger protection systems, disconnect power plants or consumers from the grid and thereby cause further deviations. Frequency control therefore belongs to the fundamental ancillary services that an electricity system needs in addition to the pure supply of energy. It is closely linked to security of supply, but not the same thing. Security of supply also includes sufficient generation and grid capacity, available fuels, reserve concepts, crisis preparedness and grid restoration after disturbances. Frequency control, by contrast, describes the ongoing balancing in operation.

Distinction from voltage, balancing energy and balancing groups

Frequency control is often confused with voltage control. Both concern stability, but they operate at different levels. Voltage is more locally or regionally determined and is closely related to reactive power, network impedances and the loading of individual lines. Frequency, by contrast, describes the instantaneous active power balance in the synchronous interconnection. A grid area can have voltage problems even though the frequency is stable. Conversely, the frequency can fall due to a large power imbalance while many local voltages initially remain within the permissible limits.

Balancing energy is also not the same as frequency control. Balancing energy is a procured and activated means of compensating frequency or balance deviations. Frequency control is the overarching task. It includes physical inertia, fast controls, automatic reserve products, manual interventions, operational specifications, market processes and emergency measures. Anyone who understands frequency control only as a balancing energy market overlooks the first seconds and fractions of a second. During this time the grid responds purely physically, before any market product can take effect.

The term must also be distinguished from balancing group management. A balancing group allocates feed-in and withdrawal in economic and organisational terms. Its deviations are settled financially and create incentives for good forecasts. Frequency control itself, however, takes place in real time. A balancing group may be planned to be balanced for a quarter of an hour, and yet a brief imbalance affecting the frequency can still occur within that quarter of an hour.

Physical response and tiered reserves

In classical electricity systems, large synchronous machines in coal, gas, hydro or nuclear power plants contribute significantly to the initial stabilisation. Their rotating masses are electromechanically coupled to the grid frequency. If a power plant suddenly fails or a large load is connected, these masses release kinetic energy for a short time. In the case of a power surplus, they absorb energy. This instantaneous reserve acts without a central request and without a communication signal. It does not prevent the disturbance, but it slows the rate of change of frequency and buys time for further measures. In addition, there is the self-regulation of load: some motor loads draw somewhat less power when the frequency falls.

This immediate response is followed by tiered reserves, which are regulated in the EU by the System Operation Guideline, Regulation (EU) 2017/1485. In Germany they are procured by the transmission system operators via a common platform. The tiers are as follows:

Frequency Containment Reserve (FCR, formerly primary control power): It is activated automatically and in a decentralised manner on the basis of the locally measured frequency and must be fully delivered within 30 seconds. In Germany this is the case at a deviation of ±200 mHz. FCR is provided symmetrically, so there is no separate product for positive and negative FCR. It arrests the frequency trajectory but does not restore the setpoint.
Automatic Frequency Restoration Reserve (aFRR, formerly secondary control power): It is controlled via a setpoint from the transmission system operator, responds after 30 seconds at most and must be fully delivered within 5 minutes. It returns the frequency to the setpoint, balances the power balance of the causing control block and replaces FCR. As a result, FCR is available again for the next disturbance.
Manual Frequency Restoration Reserve (mFRR, formerly minute reserve): It is called upon as needed in the case of larger or longer-lasting imbalances, must be fully delivered within 12.5 minutes and in turn replaces aFRR. It is needed less often and usually only for a few quarter-hours.

An overview is provided by the entry Frequency Restoration Reserve (FRR). How much FCR is needed depends on a reference incident. For the Continental Europe synchronous area, the Regulation sets 3000 MW in the positive direction and 3000 MW in the negative direction. This corresponds roughly to the simultaneous loss of two large power plant units. The transmission system operators supplement this sizing with a probabilistic approach. So that no single provider becomes a cluster risk, the FCR share per unit is limited to 5 percent of the quantity required in the synchronous area.

Figures and limits in the Continental European interconnection

For Continental Europe, Annex III of Regulation (EU) 2017/1485 specifies the following standard values: The standard frequency range is ±50 mHz, i.e. 49.95 to 50.05 Hz. The maximum instantaneous frequency deviation after an incident up to the size of the reference incident is 800 mHz, and the maximum steady-state deviation is 200 mHz. The frequency is to be restored within 15 minutes. Other synchronous areas have other values: Great Britain and Ireland, for example, work with a standard range of ±200 mHz, and the Nordic area with ±100 mHz.

Longer-lasting deviations change the system state. The alert state occurs in Continental Europe when the deviation exceeds ±100 mHz for five minutes or lies outside the standard range for 15 minutes. If the frequency falls further, the system defence plan under Regulation (EU) 2017/2196 takes effect. From 49.0 Hz at the latest, automatic under-frequency load shedding begins in stages. By 48.0 Hz, approximately 45 percent of the national load must be cumulatively disconnectable, with a tolerance of ±7 percentage points. Beforehand, where the rate of change of frequency allows, generating units in frequency-sensitive mode are to provide additional power, and storage units that are currently charging are to be switched over or disconnected. For over-frequency there are separate automatic concepts.

Frequency control in a converter-dominated electricity system

With the expansion of wind energy, photovoltaics, battery storage and many new consumers, the technical basis of frequency control is changing. Many of these installations are connected via converters, i.e. coupled to the alternating current grid by power electronics. As a result, they do not follow the grid frequency on their own in the way a synchronous machine does. However, they can be controlled so that they support the frequency, deliver fast power changes or even operate in a grid-forming manner.

It does not follow that renewable energies fundamentally worsen frequency control. What matters is not the energy source but connection conditions, control, mode of operation and system integration. A wind turbine contributes little to instantaneous reserve without a corresponding requirement. With suitable converter control it can support the frequency, though only within its technical and energetic limits. A photovoltaic installation can hold upward reserve if it is deliberately operated below its possible output. This causes opportunity costs, because usable generation remains unused. A battery storage system can provide positive or negative power very quickly. To do so, however, it must manage state of charge, marketing and reserve obligation at the same time.

Grid-forming converters are becoming increasingly important in this context. They actively set or support voltage and frequency instead of merely following an existing grid signal. In an electricity system with fewer large rotating machines, this is a central capability. However, it does not arise automatically with the construction of a storage system or a wind turbine. It must be required in connection rules, demonstrated in test procedures, integrated into operational processes and remunerated if it goes beyond the installation's own interest.

Responsibilities, incentives and costs

In the interconnected grid, the transmission system operators are primarily responsible for frequency control. They size and procure reserves, coordinate their deployment, monitor the frequency and coordinate internationally. Because the grids are synchronously coupled, frequency control in the Continental European synchronous area is a shared task. A large power plant outage in one country is initially borne by the inertia and the FCR of the entire synchronous area. Afterwards, the aFRR of the affected control block ensures that the imbalance is compensated where it arose.

Costs arise not only from the energy that is called upon. Even holding reserve capacity has a value, because installations must keep capacity free, forgo other revenues or adjust their mode of operation. For battery storage, this concerns, for example, state-of-charge management and lost trading opportunities. For power plants, it involves part-load operation, fuel costs, wear and minimum loads; for consumers, production processes, comfort limits or contractual restrictions. This shows that stability is a service in its own right and is not automatically delivered with every kilowatt-hour generated.

Market rules determine which technical capabilities are offered. Minimum bid sizes, activation times and prequalification requirements influence whether storage, smaller installations or controllable loads can participate. If ancillary services are neither remunerated separately nor mandatorily required, installations can be operated economically sensibly without contributing anything that the overall system will need in future. Conflicts arise where technical possibilities, market rules and political responsibilities diverge.

Typical misinterpretations

A widespread misunderstanding is that a balanced annual balance ensures a stable frequency. For frequency, however, what counts is not the year but the moment. Even a quarter-hour balance is too coarse for many dynamic processes. A system can generate enough energy over the year and still get into critical frequency situations if power or fast reserve is lacking in the short term.

A second oversimplification concerns baseload. In the past, large, steadily running power plants were often equated with stability. Their synchronous machines did indeed provide inertia and controllability, provided they were operated accordingly. It does not follow, however, that every form of baseload generation is necessary for frequency control. The required functions can also be provided in other ways. The question shifts from the power plant category to the specific capability: How quickly can an installation change its output, how reliably is it available, what energy or process limits does it have and under what rules is it activated?

A third misinterpretation treats frequency control as a purely technical specialist problem. Technology sets the limits, but whether the capabilities are actually available depends on institutions. Connection rules determine what installations must be able to do. Markets decide which capabilities generate revenue. Grid operators determine, within the framework of regulation, which reserves they procure and how they deploy them. Politics and regulation decide whether new requirements are formulated in good time.

Significance for electrification and flexibility

With heat pumps, electromobility, electrolysers and electrified industrial processes, the number of large and potentially controllable consumers is growing. This can be useful for frequency control if these loads adjust their power quickly and reliably. Flexibility is a measurable capability in this context. What matters is how much power can be changed, how quickly, for how long and with what advance notice, what this costs and how it affects the actual purpose of use.

Electric vehicles can shift charging processes and in future possibly feed back into the grid. A heat pump with thermal storage can be operated differently for a time. An electrolyser can reduce its load if hydrogen production is flexible in terms of timing. General potentials, however, are not enough for frequency control. They must be pooled, controlled, measured, prequalified and reliably settled. Otherwise they remain an energy-policy possibility, but not a resource for grid operation.

Frequency control thus makes tangible a basic requirement of a renewable and electrified electricity system. It is not enough to generate sufficient electricity and expand grids. The system needs fast and reliable power adjustment at all times, suitable converter functions, clear responsibilities and rules that make the value of stability services economically visible.

Sources

Verordnung (EU) 2017/1485 der Kommission vom 2. August 2017 zur Festlegung einer Leitlinie für den Übertragungsnetzbetrieb — Europäische Union, EUR-Lex; 2017-08-02. Art. 3 Nr. 41 (Netzfrequenz); Art. 153 Abs. 2 (FCR-Dimensionierung, Referenzstörfall); Art. 156 (5-%-Grenze je FCR-Einheit); Anhang III Tabelle 1
Welche Arten der Regelreserve gibt es? — Deutsche Übertragungsnetzbetreiber (regelleistung.net); unbekannt. Abschnitte FCR, aFRR, mFRR und Vergleichstabelle
Verordnung (EU) 2017/2196 der Kommission vom 24. November 2017 zur Festlegung eines Netzkodex über den Notzustand und den Netzwiederaufbau des Übertragungsnetzes — Europäische Union, EUR-Lex; 2017-11-24. Art. 15 (automatische Unterfrequenzregelung); Anhang (Parameter Lastabwurf)
Beschluss BK6-17-234 (Frequenzqualität, gefährdeter Zustand) — Bundesnetzagentur; 2019-05-02. Begründung zu Anhang III Tabelle 1 SO-VO (laut Suchergebnisauszug)
Präqualifikationsverfahren für Regelreserveanbieter (FCR, aFRR, mFRR) in Deutschland (PQ-Bedingungen) — Deutsche Übertragungsnetzbetreiber; 2022-06-03. Abschnitte zu Aktivierungszeiten und Präqualifikationsfahrten (laut Suchergebnisauszug)

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Edited by eCMS on 12.11.2026 05:05