Additional revenue from the grid for charge point operators, on any CPMS

Grid flexibility means adjusting when and how fast electric vehicles charge, so that the power system stays balanced. Charging load can be raised or lowered within seconds, or shifted across hours, which makes it valuable to system operators and to the energy market.

Four groups of buyers pay for it: transmission system operators buying frequency reserves, the wholesale and balancing markets, capacity mechanisms, and distribution system operators managing local congestion. A fifth kind of value isn't a market at all: load management can lower your own grid costs. For a charge point operator, all of this is a way to earn from charging infrastructure without installing anything new.

That depends on three things: the country and bidding zone you operate in, how much charging power runs at the same time, and what kind of charging it is. Long dwell times suit the wholesale market. High concurrent power suits frequency reserves. A constrained grid connection makes local capacity the priority. Our assessment covers all four and tells you which are realistic for your network.

Long dwell times suit the wholesale market. High simultaneous power suits frequency reserves. A grid-constrained location makes DSO services and dynamic connection capacity the priority. See which markets fit your charging network for the fit by charging type.

Thresholds are set per product, not per country. Frequency reserves require at least 1 MW of simultaneous charging power, while the wholesale and capacity markets set their own entry conditions.

Through aggregation you don't have to meet them alone. Virta pools your capacity with other operators' into a portfolio that clears the threshold, and you're paid for your share.

In practice they describe the same thing from two directions. Demand side response, or DSR, is the term used in Great Britain for consumers adjusting their electricity use to help balance the system. Demand response is the equivalent term used more widely across Europe. Grid flexibility is the broader label for the capability itself, whoever is buying it.

For a charge point operator the distinction rarely matters commercially: what is being sold is adjustable charging load, and the buyer and the payment model depend on the market rather than on the name.

FCR, or frequency containment reserve, is capacity that automatically adjusts electricity consumption or generation to keep grid frequency stable at 50 Hz. Transmission system operators such as Fingrid in Finland and Svenska kraftnät in Sweden procure it through market-based tenders and pay providers for keeping the capacity available. FCR is one of several ancillary services, alongside frequency restoration reserves (aFRR and mFRR) and fast frequency reserve (FFR).

FCR-N, frequency containment reserve for normal operation, keeps frequency within the normal band of 49.9 to 50.1 Hz. It is a symmetrical product: the resource must be able to regulate both up and down. FCR-D, frequency containment reserve for disturbances, handles larger deviations between 49.5 and 50.5 Hz and is procured as two separate products, FCR-D Up and FCR-D Down. FCR-D activates rarely, in response to actual disturbances.

Yes. A charge point delivering power to a vehicle is an adjustable load, and its power can be reduced or increased within seconds. That is what a reserve resource does. Individual charge points are far too small to enter reserve markets alone, so they're aggregated: many charge points across many sites combined into a single portfolio that behaves as one resource.

You're paid a capacity payment for each MW of reserve capacity held available, for each hour it's available. The payment is for availability, so it applies whether or not the reserve is called upon. Prices are set in the TSO's market and vary by product, hour and market conditions.

There is one cost to weigh against it. Symmetrical products need room to regulate in both directions, so committed charge points run below full power during committed hours. We include that in the model rather than leaving it for you to find later.

Minimally. Reserves respond to grid frequency, and frequency stays within normal limits the overwhelming majority of the time. When a response is required, the charging power of participating charge points adjusts briefly before returning to normal. FCR-D in particular activates only during actual grid disturbances, which are infrequent. You also set which parts of the network take part and within what limits.

Before any resource can provide reserves, the TSO requires prequalification tests demonstrating that it responds correctly to frequency deviations. For aggregated resources this includes a technical description of the aggregation system. Virta runs this process on your behalf.

Charging is scheduled towards the cheaper hours within the time a vehicle is plugged in, and the saving is the price difference between the hours you avoided and the hours you used. Charging can also be offered into the balancing market, where an accepted bid is paid per MWh. Both depend on energy actually being moved, so a flat price curve earns nothing.

More than reserves do, because the load is being shifted across hours rather than adjusted for seconds. Sessions can start later or charge more slowly. That's why it suits long dwell times, and why the guardrails matter: you set which sites take part, and the schedule works to a readiness time.

No. Your existing electricity contract can stay as it is.

A capacity mechanism pays resources to be available at the hours when the system is most likely to be short, rather than for the energy they deliver day to day. Demand-side resources such as charging load can take part, usually with a de-rating factor applied to the volume and a metering baseline agreed in advance.

Capacity agreements carry a delivery obligation, and missing it carries a financial penalty. This is the main way a capacity mechanism differs from a reserve product, so it belongs in the decision rather than the fine print. Events are rare and notified in advance, and the commitment is sized against load we know is dependable.

A distribution system operator buys load reduction at a specific location and time, to relieve congestion on a particular part of its network. Eligibility therefore depends on the exact location of your charging within a municipality or electrical grid branch, so two sites in the same city can differ. We check your sites against the products available where they sit.

Often, yes, and this is separate from any market. Dynamic load management holds a site under its peak-power tariff band, which lowers the grid fees of the site and can create room for more chargers behind the existing connection. The value depends on your tariff structure and your connection headroom.