Imbalance Payments in Energy Markets

Risk management conundrum in 2025: What do you do when imbalance costs exceed 50% of your total revenue from power production? 🤔 A couple of years ago a scenario like this would be unthinkable. But here we are. Power producers have two main input factors for their income: 💶 Prices ☀️ Production Both have become significantly more uncertain. And hence, revenue uncertainty has increased, too. Case in point: “We have decided to stop production at all plants during weekends with low electricity prices in order to eliminate the risk of having to pay a high price for production during these days,” a power producer told Montel News. They experienced that over 50% of revenues were eaten up by imbalance costs in March. Basically, the cost of correcting differences between actual production and electricity sold on power markets. Being exposed to market downswings on weekends was judged to be riskier than the reward of selling energy. To completely stop production is a strong reaction and comes with an alternative cost. But I understand the rationale behind the decision. A main contributor to the imbalance expenses was two hours on March 23 with -10,000 EUR/MWh imbalance prices. Meaning, you must pay 10,000 EUR for producing one MWh over your plan 🤯 Where there’s uncertainty, there’s risk. This is true for power markets. And the risks have increased together with uncertainty in production and price volatility. Risks and their management are not new for power producers. But their nature has changed. It used to be long-term risks they would hedge. Now we see short-term risks having larger impact on producers’ bottom lines. As the nature of risk changes, so must the risk management. A key is to properly assess the uncertainty and risks in the short-term electricity markets in real time and automatically change exposure accordingly. Although the future is uncertain, you can still have risk-reward optimal exposure.

Have you ever wondered why the old Balance Responsible Parties (BRPs) (Centrica, Varberg Energi, Mind Energy) complain so much about imbalance prices?   The graph below illustrates the difference between the spot price and the imbalance price for each imbalance settlement period (ISP) year to date.   Usually, the price difference is the most important metric for the BRP because they are exposed to the spot price agreements with customers or the trades made in the day-ahead market. Therefore, the difference is what they need to pay themselves.   A first observation is that the price differences have increased significantly and that gives every MWh of imbalance a very high risk of substantial loss.   You might think that very high penalties for imbalances serve as a good motivation to reduce them, but they actually increase the imbalances. The reason is that the imbalance price risk is non-Gaussian distributed, exhibiting a longer tail upwards than downwards, making negative imbalances more risky than positive imbalances.   Renewable generation involves fundamental uncertainty about production volumes. A way to reduce the risk of negative imbalances is to intentionally create positive imbalances. When many BRPs do that, it will result in imbalance prices that are generally negative unless larger unexpected imbalances occur.   The negative imbalance price bias shows how afraid the BRPs are, because they are willing to pay a premium of 50-100 €/MWh for an intentional positive imbalance position to reduce the risk of having a negative imbalance price.   Is that bad for renewable generation projects? Yes, because in the end, those asset owners will have to pay that cost via higher volume fees to the BRP. Hybrid Greentech - Energy Storage Intelligence

𝐖𝐡𝐚𝐭 𝐅𝐢𝐧𝐥𝐚𝐧𝐝’𝐬 𝐢𝐦𝐛𝐚𝐥𝐚𝐧𝐜𝐞 𝐩𝐫𝐢𝐜𝐞𝐬 𝐬𝐚𝐲 𝐚𝐛𝐨𝐮𝐭 𝐭𝐡𝐞 𝐟𝐮𝐭𝐮𝐫𝐞 𝐨𝐟 𝐍𝐨𝐫𝐝𝐢𝐜 𝐛𝐚𝐥𝐚𝐧𝐜𝐢𝐧𝐠 𝐦𝐚𝐫𝐤𝐞𝐭𝐬!   Since March 2025, the Nordic balancing market has entered a new phase — one of higher volatility, structural reform, and cross-border integration. Ahead of the Finnish Energy Day 2025 on 12th June, I have written a blog titled, "Balancing in transition: how Finland’s imbalance prices reflect Nordic market reforms". Here are a few highlights:  🔹 15-minute settlement and automated mFRR clearing Market granularity has improved, and the price volatility has increased. Market participants can now operate on faster, more dynamic timeframes.   🔹 Finland’s PICASSO integration On 27 March 2025, Finland joined the European aFRR platform PICASSO — following the local aFRR market launch in June 2024. Finland’s imbalance prices are now driven by a combination of mFRR and aFRR activations, with mFRR setting the dominant price.   🔹 Sharp rise in price volatility  Upward imbalance prices have peaked at €5,000/MWh Downward imbalance prices have dropped to -€10,000/MWh Scheduled mFRR activations have significantly increased in volume and frequency   🔹 Bidding behaviour is shifting Market actors are adjusting their behavoir:  Most extreme upward mFRR bids are now available at lower prices than before. Downward bids are higher priced — reflecting flexibility needs and volatility.   🔹 TSO proposals to stabilise the market SVK: about to introduce a ±25 MW tolerance band for direct activations to reduce price spikes. Energinet: Round mFRR demands ≤25 MW to 0 MW to prevent small-volume volatility.   🔹 Outlook With more hours now seeing prices set by mFRR, understanding this shift is critical for market strategies. 📈 Data transparency, market cooperation, and advanced analytics will be key to navigating the increasingly complex Nordic power market.   👉 The link to my full blog can be found in the comments section.   #EnergyMarkets #NordicPower #BalancingMarkets #MontelAnalytics #MontelEnAppSys #EnergyTransition

Update of the graph concerning the distribution of the components determining the imbalance price in Belgium before and after PICASSO. The initial post is here: https://lnkd.in/eiDKpNit Explanation: In Belgium, the imbalance price is either a deadband value if the System Imbalance (SI) is below -25 MW (in absolute term). If the SI is below -25 MW, the imbalance price is the maximal value between a "Floor", an aFRR+ component, and a mFRR+ component. Inversely, if the SI is above +25 MW, the imbalance price is the minimal value between a "Cap", an aFRR- component, and a mFRR- component. The floor and cap values are determined by the Value of Avoided Activation, which are determined based on the local aFRR/mFRR components and corresponding to the cheapest energy bid. Before PICASSO connection, the imbalance price was virtually always determined by the aFRR and mFRR components, as these components were solely based on the Belgian merit orders for aFRR and mFRR. And most of the time, the aFRR component was the determining factor. After the PICASSO connection, the aFRR components are determined by the Cross-Border Marginal Prices (CBPM), depending on the aFRR merit order of neighboring countries and available capacity at the borders. After one day, we can observe that the imbalance price has been quite often determined by the floor value and to a lesser extent, the cap value. It means that, practically, the CBMP has been more advantageous than the cheapest available resource in Belgium. Of course, it is only based on a very limited time after the PICASSO connection and the market behavior can evolve. About the graph: blue bars are before PICASSO in November and orange bars after PICASSO. Yellow rectangle is the deadband (value is the average between Cap and floor), red rectangle is when SI is below -25 MW, and green rectangle, when SI is above +25 MW. PS: there is also an additional component called "alpha" added to the imbalance price.