Executive Summary

• Battery energy storage revenues in Great Britain reached £88k/MW/year in January 2025, marking a 5% increase from December 2024 and the first back-to-back monthly revenue increase since early 2024.
• Wholesale trading revenues surged by £11.6k/MW/year, driven by 42% higher wholesale price spreads, which hit a two-year high.
• Intraday power prices peaked at £1,780/MWh on January 8th, leading to the highest single-day battery revenues since 2022, with earnings of £394k/MW/year.

Subscribers to Modo Energy’s Research will also find out:

• How Reserve services revenues climbed to a new high, following December’s Quick Reserve launch.
• The impact of a National Energy System Operator (NESO) Capacity Market Notice on battery participation on January 8th.
• Why Balancing Mechanism revenues fell by £11k/MW/year, despite rising overall battery earnings.

To get full access to Modo Energy’s Research, book a call with a member of the team today.

Battery revenues increase in back-to-back months

The first quarter of 2024 saw battery revenues increase month on month from their January low to March. Throughout the rest of the year, battery revenues fluctuated as they followed wind generation - rising and falling each month. In December 2024, battery revenues increased 65% to £84k/MW/year.

Balancing Mechanism revenues fell by £11k/MW/year as batteries saw a 40% reduction in dispatched Offer volume. Revenues also fell in the Frequency Response services following lower prices in the Low services.

However these reductions were offset by increased revenues in the Reserve services and from wholesale trading.

In December the launch of Quick Reserve contributed to a £10k/MW/year increase in Reserve revenues, leading them to their highest levels since the launch of Balancing Reserve in March 2024. In January, Reserve revenues increased another £3.6k/MW/year to a new high.

Similarly to December increased revenues in January were driven by high wholesale prices, leading to increased power price spreads. Wholesale revenues increased by £11.6k/Mw/year resulting in a two year high.

Various factors, including wind generation, gas and carbon prices, and in-merit dispatch rates drive battery revenues. January saw an increase across most of these macro factors, including a 42% increase in wholesale price spreads.

Day-ahead wholesale price spreads increase by 42%

Day-ahead wholesale price spreads increased to £136/MWh on average in January 2025. This is the highest they have been since December 2022, where they hit £225/MWh. Wholesale price spreads exceeded £200/MWh on several days in January, reaching £885/MWh on 22nd January.

Intraday power prices led to highest revenue days since December 2022

There were several high-priced days in January in the day-ahead wholesale market. This was driven by periods of low wind generation, coupled with high demand during this winter season increasing output from more expensive gas units. January 8th - 10th as well as January 20th - 22nd saw prices above £200/MWh. The N2EX Day-ahead hourly price peaked at £980/MWh on 22nd January.

However, more notably, in the EPEX Intraday market, on January 8th, prices reached £1,780/MWh at 16:30. The highest intraday price since January 2022, when prices hit £3.1k/MWh.

Batteries earn their highest single day revenues since 2022

As a result of the unusually high intraday price, batteries earned £394k/MW/year on January 8th 2025. This beats the recent high that was set on 12th December 2024 to become the single-highest revenue day since September 2022.

Around 50% of battery wholesale volume traded on the day was traded through the intraday market. To find out more about our wholesale trading revenue methodology, head to the full article.

NESO issues its third Electricity Capacity Market Notice since October 2024

On 8th January 2025, the National Energy System Operator (NESO) issued an Electricity Capacity Market Notice (CMN) for 16:30 the same day. An ECMN is defined by NESO as below.

A Capacity Market Notice is a signal four hours in advance that, when taking into account additional operational reserve requirements, there may be less generation available than National Energy System Operator (NESO) expects to need to meet national electricity demand on the transmission system. The notices are intended to be a signal that the risk of a System Stress Event in the GB electricity network is higher than under normal circumstances.

​​NESO logs Electricity Capacity Market Notices (ECMN) / Capacity Market Notices (CMN) here. This link can be used to find when the latest and previous Electricity Capacity Market Notices / Capacity Market Notices were issued [gbcmn.nationalenergyso.com].

A Capacity Market Notification is automatically triggered when less than 500 MW of surplus generation is expected above the required operational margin between generation and demand. This is triggered four hours ahead of time. An Electricity Margin Notice (EMN) was also issued for the January 8th, the day before. EMNs are different to CMNs as they come directly from the control room engineers when they have concerns about the availability of generation in future.

At the time of the CMN, the sum of transmission demand and operating margin was 46.7 GW, whereas the expected generation was 47.1 GW, leading to a surplus of 449 MW. As this surplus was below 500 MW, it triggered the notice.

Low wind generation and reduced interconnector availability squeezed margin

NESO attributed the notices to a 2 GW reduction in wind generation forecast and an increase in demand due to the cold weather. In addition to this 3 GW of interconnectors were unavailable.

The Viking Link interconnector to Denmark had been operating at 50%. The 1 GW BritNed connecting Great Britain to the Netherlands had a planned outage since 6th December 2024.

At eight hours ahead of time, the de-rated margin for 17:00 was forecast to be 510 MW, by one hour ahead this had risen to 1 GW.

Higher wholesale price spreads as a result of reduced generation due to interconnector unavailability and generator outages was expected as part of our winter outlook analysis.

3 GW of batteries responded to system needs at peak time on January 8th

On January 8th, batteries provided at least 3 GW of flexibility at 17:00. Batteries supported the system across a range of services. 1.5 GW were contracted to export power in the wholesale markets.

In addition to this, 1 GW was contracted in frequency response services to manage the frequency changes on the grid. This also does not account for the batteries that are not registered in the Balancing Mechanism, which may have been supporting the grid via the wholesale market.

On the other hand, as NESO’s requirements for generation were met, some batteries were even turned down in the Balancing Mechanism.

In the end demand was lower than expected at 45.8 GW and margin was over 1 GW. NESO worked with Viking Link to ramp it up to its full 1.4 GW capacity to support the shortfall. In addition to this, the Demand Flexibility service was also used to provide up to 184 MW of reduced demand across the period.

Additional low wind days in January led to the increase in revenues from December

In addition to the high intraday prices on January 8th, there was an increased number of periods where residual demand exceed 20 GW compared to December 2024. This drove wholesale prices up, increasing the spread, leading to the higher revenues seen in January.

Frequency response clearing prices increased leading to higher revenues

High wholesale prices usually lead to higher frequency response prices. In January this was seen as the average clearing price increased from £3.58/MW/hour to £3.63/MW/hour.

This was mostly driven by an increase in Dynamic Regulation Low prices, which saw a 21% increase. Dynamic Containment Low also saw its second price increase in a row, taking it to £5.39/MW/hour.

Although prices increased on average, frequency response revenues decreased by 12% from December. This is because the ME BESS GB Index is based on Balancing Mechanism Units (BMUs) and these batteries are more likely to provide High services. Prices went down in all of these services.

This is due to the differences in how BMUs and non-BMUs operate on the grid.

The energy non-BMUs export or import while performing frequency response is not subject to Applicable Balancing Services Volume Data (ABSVD). This means they are 'out of position' by how much they import or export, and pay the imbalance price for this energy. As a result, non-BMUs avoid High services, as they involve importing energy - which would mean they pay the imbalance price. Instead they favor Low services, which involve exporting. This means they are paid (if the system price is positive) for the energy they export while providing these services.

BMUs do get ABSVD, this means they are more likely to participate in the High services, as they are not exposed to the system price for their imports. In order to provide Low services, they require higher prices, as they export energy to provide the service without being paid for it. This means they cant compete with non-BMUs on price and are less likely to be accepted.

Battery Offer dispatches came down from their record high in the Balancing Mechanism

The Balancing Mechanism was the only other revenue stream to see lower returns in January 2025. Batteries earned £10k/MW/year in the service, less than half of their December Balancing Mechanism earnings.

This comes as batteries saw a 40% reduction in their dispatched Offer volume from the all time high they dispatched in December.

Batteries saw a higher amount of available Offer volume in the Balancing Mechanism in January. However, 37% of this was in-merit, compared to 44% in December. While less volume was in-merit, the proportion of this that was dispatched was lower compared to December. In December 18% of available in-merit Offer volume from batteries was dispatched compared to 12% in January