The path to FID for developers of renewable generating assets is often paved with uncertainties and challenges. Some of the key questions when evaluating the business case of a future wind or solar farm can be boiled down to:
- CAPEX estimation,
- Yield estimation, and
- Estimation of the market value of the power produced from the renewable generating asset.
In one of our recent articles ‘Brace the high wind speed’, we dealt with one of the key elements in 3, namely price cannibalization, and how recent strengthening of offshore wind capture rates in the Danish bidding zone DK1 gave grounds for optimism.
On a less optimistic note related to the realized market value of the generated power, operators of wind farms in DK1 have experienced a substantial increase in imbalance cost since Energinet’s change of the imbalance price design and related market structures one year ago driving up imbalance costs for wind by 140% in the 12 months after the change compared to the 12 months prior[1].
Changing market structures
In March 2025, Energinet rolled out several market changes impacting the price setting of imbalances in DK1.
aFRR enters the equation
Already back in October 2024, the Danish bidding zones joined PICASSO, the panEuropean market for Automatic Frequency Restoration Reserves (aFRR) provision which simultaneously introduced a separate aFRR price. According to European regulation, this entails that the aFRR price must enter the imbalance price equation which then subsequently was enforced in March 2025. Previously, the imbalance price in DK1 was set purely based on the price of providing Manual Frequency Restoration Reserves (mFRR) in the dominating direction. With the updated imbalance price design, the imbalance price in the case of upregulation being the dominating direction is set as the max of the mFRR prices and the volume weighted aFRR price. For downregulation, it is the minimum of the prices. In the case of no dominating direction, the imbalance price remains to be set equal to the spot price
mFRR EAM and higher temporal granularity
Also in March 2025, Denmark entered the Nordic mFRR Energy Activation Market (mFRR EAM). This had several implications for the price setting of mFRR in DK1, one of which was that the price setting went from hourly to quarter hourly basis. BLUE POWER PARTNERS • Imbalance costs In addition to changing the time granularity on the mFRR price and changing the equation for calculation of the imbalance price, the time granularity for which the imbalance price is calculated was also changed. While settling of imbalance volumes moved from 60 to 15 minutes basis in 2023, the setting of the imbalance price itself remained on a 60 minutes basis. That is, until March 2025 where also the calculation of the imbalance price and determination of the dominating direction moved to a 15 minutes basis.
Flow-based market coupling
In the end of 2024, the Nordic bidding zones transitioned to flow-based market coupling. The flow-based model has only been introduced for the cross-zonal trades in the day-ahead market which is reported to have reduced the transmission capacity available for cross-zonal intra-day trades and provision of ancillary services ultimately driving scarcity of the latter.
How new market structures drive up imbalance costs
Several of the market design changes Energinet introduced in 2025 can drive up the cost of being in imbalance almost by construction.
The immediate implication of going from the imbalance price being set exclusively based on the mFRR price to the imbalance price being a function of both the mFRR and aFRR prices is somewhat straight forward. In the case of the dominating direction being up, the imbalance price will be set as the higher of the mFRR and the volume weighted aFRR, hence meaning that if the volume weighted aFRR price is higher this would result in a higher imbalance price than under the previous imbalance price design. Similarly, an aFRR price lower than mFRR will drive down the imbalance price under down-regulation.
The fact that the determination of the dominating direction also was changed from 60 to 15 minutes basis is key to understanding why the change of the time granularity in the imbalance price may lead to higher imbalance costs. If we envision a 60-minute MTU where the dominating direction across the 60 minutes was down, there could have been a 15 min period inside the hour where the dominating direction would have been up. Despite the price of providing mFRR upregulation in that quarter-hour may have been extremely high, given that the overall dominating direction across the entire hour was down, the price would have been set based on the price of providing downregulation without the extreme high price entering the imbalance price equation.
Instead, in the new market design where the imbalance price and dominating direction is determined on the quarter hourly level, the aforementioned 15 minutes period would have seen an extremely high imbalance price for that quarter. The same arguments apply to how the previous hourly aggregation now no longer will smooth out potentially very low imbalance prices in quarter hours dominated by down-regulation. The impact is aggravated by the introduction of the flow-based model leading to scarcity of balancing services due to higher reliance on local mFRR balancing services, where even a short duration scarcity can have direct impact on imbalance prices.
The empirical evidence of increasing imbalance costs
The spread between the imbalance price and the day-ahead price indicates the cost of going into imbalance. In the case of down-regulation the spread indicates the cost of either feeding-in a higher than nominated volume or consuming a lower than nominated volume when the system has surplus power. For up-regulation the spread indicates the cost of feeding-in less than nominated or consuming more than nominated when there is a lack of power in the system.
The spread has increased significantly in both directions following the market changes from Energinet. In the case of down-regulation, the imbalance/DAM-spread has increased from 38 to 53 EUR/MWh (+39%) and in the case of up-regulation the spread has increased from 92 to 123 EUR/MWh (+33%).
While the increased spread has provided owners of batteries and other flexible assets very lucrative market conditions, it is more of a headache for owners and balancing responsible parties of wind and solar farms.
Figure 1: Imbalance/DAM-spread in DK1
As several changes to the market structures were made at once, it is difficult to isolate the impact of the individual changes on the imbalance prices. However, comparing the spread between the imbalance price and the day-ahead market price to the spread between the mFRR price and the day-ahead price tells us something about the impact of the aFRR price entering the imbalance price equation; and it turns out it is quite substantial.
Since the system change, in periods with downregulation the average Imbalance/DAM-spread was 53 EUR/MWh while the mFRR/DAM-spread was 32 EUR/MWh indicating that the lower aFRR price contributed by increasing the cost of being in imbalance under downregulation by 21 EUR/MWh (+67%). In periods with upregulation, the aFRR price component contributed to increasing the imbalance spread by 53 EUR/MWh from what would have been 70 EUR/MWh had it only been based on the mFRR price to instead be 123 EUR/MWh (+76%) under the new design.
Figure 2: Spreads under down-regulation (since 19 March 2025)
Figure 3: Spreads under up-regulation (since 19 March 2025)
If we look at the distribution of the spread, we also see a very large change in the occurrence of the different levels of spreads.
In the 12 months before the system change in March 2025, the majority of MTUs saw spreads close to zero and specifically 57% of MTUs with the imbalance price within 10 EUR/MWh of the DAM price.
Instead after the system changes, the distribution has flattened more out. In comparison to the 57% before, in the 12 months after only 27% of imbalance prices has been within 10 EUR/MWh of the day-ahead price making it more costly to go into imbalance. The fraction of MTUs where the imbalance price is 50 EUR/MWh or more lower than the day-ahead price has increased from 12% of MTUs to 28% making it more often very expensive to have a long imbalance position. At the same time, extremely high imbalance prices have become more frequent with the occurrence of MTUs with spreads above 300 EUR/MWh having gone from 1% to 3%.
Figure 4: Imbalance/DAM-spread 12 month prior to change
Figure 5: Imbalance/DAM-spread 12 month after change
Rising imbalance costs for wind
The increasing spread between the imbalance and day-ahead prices drives up the associated cost faced by wind operators due to their imperfect foresight of production when nominating volumes in the day-ahead market.
When comparing the 12 months prior to the market changes in March 2025 to the 12 months after, the imbalance cost per MWh incurred by the wind operator has increased 140% after the market changes with individual months being as high as +600% compared to the average of the year prior.
Below is illustrated the indexed monthly development in imbalance cost per MWh wind production in DK1 with the indexation basis being the average imbalance cost of the year prior to the change.
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Figure 6: Imbalance cost index for wind[2]
From the graph below, it can be seen that the majority of the imbalance cost and its increase stem from the long imbalance positions with an average imbalance cost contribution of 84%. This long contribution alone is twice the size of the total imbalance cost in the preceding 12 months and is a result of the increase in negative Imbalance/DAM-spreads illustrated in the previous section. The short positions contribute the remaining 16%.
Figure 7: Wind imbalance cost index breakdown[2]
The increase in the frequency of extremely high imbalance prices poses a risk for wind operators that in the case of over-forecasting production would have their short imbalance position covered at these extreme prices. The balancing responsible party of a wind farm may choose to be conservative in their nomination of the wind production to avoid getting hit by extreme imbalance price when they are short and potentially steer with detailed set-point adjustment to capture windfall profits.
Both the level of the imbalance costs and the long/short contribution split naturally are direct functions of the production forecast and the characteristics of its forecast error. The forecast used in this article has an inherent under-forecasting/nomination bias. The graph below illustrates a simple sensitivity related to if the wind forecast instead had yielded an overnomination of production with a bias of the same magnitude as that of the underforecast bias. Although the approach here is simplified, the results are indicative of the risk renewable operators face when nominating their production and how in particular over-forecasting can lead to extreme imbalance costs.
Figure 8: Overforecasting sensitivity – Indexed imbalance cost breakdown[3]
Future outlook for imbalance costs
The increase in the cost of being in imbalance in DK1 discussed in this article is driven by structural changes and outside of likely some mitigating impact from DAM going to a time granularity of 15 minutes there is nothing pointing to the impact of these changes being temporary. There are however other factors that are likely to mitigate this and reduce imbalance costs from the levels observed over the last year.
Some of the recent decrease in the spread between the imbalance and day-ahead prices can likely be attributed to seasonality, partially due to the increased flexible demand from heating during the winter months, but the continuing electrification of heating in Denmark is only likely to continue driving down imbalance cost in future winters. At the same time, more BESS capacity has come online lately and with the trend of co-locating BESS and solar assets, we may see even stronger seasonality with low spreads during the winter due to more available BESS capacity in winter months with limited sun.
While it has gotten increasingly expensive to be in imbalance, it has become symmetrically lucrative to provide ancillary services. This is continuing to drive a sharp increase in the appetite for investments in batteries, and as the installed battery capacity in DK1 grows in the coming years, the level of the imbalance costs is expected to drop. In one of our next articles, we will dive deeper into how the profitability of batteries is impacted by the current jump in installed battery capacity.
