The Dutch energy market is heading into a period of major transformation in 2026; which is mostly driven by both European integration efforts and national implementation of the new Energy Act.
These regulatory and operational updates affect every part of the market chain from suppliers and aggregators to grid operators and balance parties. And hence, they shape how energy is produced, traded, allocated, and managed.
Let's dive into the key changes scheduled throughout 2026, and see what energy market participants can expect across several major releases.
The January 2026 release introduces the first wave of changes brought on by the new Dutch Energy Act. The key changes in this release revolve around the introduction of New Market Participants; the Energy Act introduces new roles alongside the ‘regular’ energy supplier, enabling greater market participation and flexibility of end-consumers.
As of January 2026, the following roles can be registered in the supplier register maintained by DSOs:
If an active consumer wishes to have a ‘regular’ supplier to cover their consumption and an aggregator sell their production, they cannot have both on the same allocation point – therefore, a separate meter and allocation point will need to be created.
As the Balance Responsible Party (BRP) market role commonly receives data on the level of grid area/supplier (e.g., in allocation and reconciliation processes), it will be interesting to see the impact of the various new ‘supplier’ roles on the amount of data the BRP receives.
Congestion management is becoming increasingly necessary due to limited transport capacity in electricity grids, caused by higher demand and decentralized renewable generation.
To resolve congestion issues, grid operators (TSOs and DSOs) employ mechanisms such as capacity restriction contracts and redispatch, which are offered by Congestion Service Providers (CSPs).
At present, market players lack sufficient insight into the connections, market roles and activations in congested areas. To help resolve this, Congestion Management Tranche 1 (otherwise known as the March 2026 release) is the first release of collective congestion management – the objective of which is to provide accurate, timely, and complete information to market players involved in congestion management.
To this end, three core processes have been approved to improve transparency in the congestion management process, under TS048 Inzicht In:
Be aware: There was originally a fourth agreement, which involved the distribution of contact details of > 1 MW connections to CSPs – this has since been removed from the scope, but the numbering of the above processes was kept as 2-4 by MFFBAS (i.e. number 1 was removed).
Below is a summary of the new information flows under Congestion Management Tranche 1:
The functionality described under Congestion Management Tranche 1 is currently optional for market parties. However, the redispatch activation message towards the BRP (TS048-3) is expected to become mandatory in the future – in a later congestion management release, a transport restriction (‘limit value’) will be placed upon the relevant connection point, which the BRP must operate within. When this happens, redispatch activations will likely become operationally required, rather than optionally informative.
Tranche 4 is the final tranche under the Allocation 2.0 collective. Previous tranches had quite clear clarity of purpose; tranche 1 concerned updated to measurement data, tranche 2 involved updates to allocation methodology, and tranche 3 introduced new reconciliation processes.
The changes introduced in tranche 4 are more distributed across the information chain:
The following market changes are included under the scope of Tranche 4, and will go live on the 1st May 2026:
Currently, allocation for small-scale (KV) connections is largely based on profile (PRF) methodology, using generic profiles and historical data to estimate consumption. This is because at present, allocation using meter data from remotely readable smart meters legally requires unambiguous consent from the consumer – meaning that many connections even with remotely readable meters are currently allocated based on PRF methodology. The current process requiring explicit consent is known as individual smart meter allocation (iSMA).
The new Energy Act provides a legal basis for DSOs to collectively read smart meters for allocation purposes, without requiring explicit consent from the consumer – however, the consumer will still retain the right to request that the grid operator switch off the remote meter reading. This new methodology is referred to as collective smart meter allocation (cSMA).
From the go-live of Tranche 4 (May 2026), all KV connections with a remotely readable smart meter will automatically switch to SMA allocation under cSMA. This will result in a massive shift in KV allocation method from PRF -> SMA; roughly 85% of the PRF volume:
The dynamic profile fractions used in PRF allocation are also being slightly adjusted under TS040, with a provisional version on D+1 and a fixed version on D+2 (currently, only a fixed D+1 version exists). There is no change in their distribution, however.
The Electricity Code of Concepts defines ‘residual volume’ as:
The volume that has not yet been allocated, after allocation of measured offtakes and feed-ins, calculated offtakes and feed-ins, and the grid loss.
In the current allocation method, the entire residual volume is allocated across profiled (PRF) connections; this is then corrected by the reconciliation process, in which differences between allocated volumes and actual meter data are settled - therefore fairly redistributing the residual volume.
While PRF connections are responsible for a large part of the residual volume due to their unmetered nature, they are not solely responsible for it – rather, about 74% of it. 12% is caused by measurement errors, and the remaining 14% is caused by grid loss. Additionally, the number of PRF connections will drastically reduce with TS040 SMA Allocation, making them unsuitable for bearing the entire residual volume alone.
Therefore, it has been decided to adjust the way the residual volume is distributed to also include grid loss unpaid consumption, as this category of grid loss is inherently uncertain – it is difficult to estimate the energy taken from the grid without a valid contract.
There are no process changes for market parties arising from TS039; PRF allocation points will simply have changed allocation volumes, due to bearing less of the residual volume.
In current market processes, the supplier determines the meter readings for small-scale (KV) connections and sends these onto the distribution system operator (DSO), who uses them to calculate volumes for reconciliation.
For SMA allocated connections, this process is preceded by a readout request from the supplier to the DSO, after which the DSO reads the meter remotely and makes these meter readings available to the supplier. This results in the following metering chain:
Instead of these four message streams, the same process can be performed by the DSO as the manager of the remotely readable meter, requiring only one message stream. Therefore, it has been decided that the DSO will determine the meter readings and transition volumes for KV connections with a remotely readable meter, instead of the supplier. This concerns the following situations:
The DSO shall make the determined meter readings and volumes available to the supplier no later than the 15th working day after a mutation, request or end of month.
IC280L was initially included in Allocation 2.0 Tranche 3, alongside the newly introduced TMT and SMA reconciliation processes. However, it was largely removed from the scope.
Now, IC280L is being implemented alongside Tranche 4, but decoupled from it – as it is essentially an extension of Tranche 3 reconciliation functionality:
As with the Tranche 3 reconciliation processes, here at Eneve we are providing a full solution for the retrieval of the new PRF reconciliation messages and storage of the data, with volume cross-checks ensuring that our clients remain in control of their reconciliation data.
Energy bids are being implemented for mFRRda (manual Frequency Restoration Reserves directly activated) also known as ‘Incident Reserves’ - this is a balancing product provided by Balance Service Providers (BSPs) to TenneT, and is activated after aFRR (automatic Frequency Restoration Reserves) to stabilize prolonged frequency deviations.
Up until now, mFRRda only had a capacity auction, meaning the only way to participate was having a capacity bid selected by TenneT via APFAS (the auction platform for ancillary services). The introduction of the energy bidding process for Incident Reserves in June 2026 has the following impact:
In addition to this, the already existing energy bidding messages for aFRR and redispatch will be updated to XML format in the future, ensuring the harmonization of the bid message format. The start of the transition for these messages is expected in Q2 2026.
Here at Eneve, we are providing a solution for the new energy bid messages, ensuring that our BSP clients can continue to participate in the ever-changing balancing market.
Following TenneT’s integration with the PICASSO platform in October 2024 (the European platform for exchanging balancing energy of aFRR) TenneT plans to connect to the European MARI platform on the 2nd December 2025 – this is the Manually Activated Reserves Initiative, which refers to the implementation of a European platform for exchanging balancing energy of mFRR.
TenneT’s integration with PICASSO had no IT impact for market parties – the existing aFRR product in the Netherlands was simply coupled with the European market, allowing for activation based on the European balancing situation. TenneT’s integration with MARI is a different story, as it marks the launch of ‘standard’ mFRR; this is a new, separate balancing product from mFRRda in the Netherlands (Incident Reserves), and is specifically designed for cross-border optimization and integration with the European balancing market, allowing Dutch BSPs to be activated by foreign TSOs (and vice versa).
Since this is a different product than Incident Reserves with its own specifications, processes and message flows, BSPs need to qualify for mFRR via MARI separately.
TenneT is introducing a number of updates to the market, with the ambition of reducing imbalance fluctuations improving the balancing situation of the Dutch electricity grid:
A scarcity component will be introduced, increasing the imbalance price during situations of scarcity when TenneT has utilised all available means, yet some power imbalance remains. This has currently been postponed, with a new implementation date to be published in early 2026.
Publishing the balance delta five times per minute (every 12 seconds) instead of once per minute from November 2025 – this will give market parties greater insight into the current balancing situation of the grid.
TenneT will publish the available cross-border capacity for balancing energy in Q1/Q2 2026, facilitating the provision of balancing energy in neighbouring countries for BSPs with international ambitions.
Adjustment of the balancing energy price in the Netherlands – during the implementation of PICASSO for exchanging international aFRR, it was decided not to include the cross-border marginal price (CBMP) in the Dutch imbalance prices. Instead, the balancing price was based on the highest activated FRR energy bid in the Netherlands, even if a more expensive bid was activated abroad. The main reason for this was to avoid price spikes in the CBMP.
Larger pools of allocation points will be permitted for BSPs – these are currently constrained by the 20MB file size limit in the ‘Activated Energy’ messages for aFRR and Incident Reserves. TenneT’s balancing team is working on a solution that will enable BSPs that risk exceeding this file size to send these messages, facilitating the participation of aggregators who may rely on large pools of assets (600+ EAN codes) to provide balancing services.
The cross-zonal gate closure time for the intraday market will be shortened – this refers to when the possibility to trade with foreign markets ends, which is currently a full hour before delivery. TenneT intends to shorten this period to 30 minutes, allowing Dutch market parties to access the liquidity of neighbouring markets closer to real-time while incorporating the most up-to-date forecasts, reducing imbalance risk. European regulations require this change by 1st January 2026, but TenneT has requested a temporary postponement to the 14th January 2026, citing grid security concerns.
Taken together, the releases from late 2025 through 2026 represent some of the most comprehensive modernization efforts the Dutch electricity market has ever seen. The new roles enabled by the Energy Act expand participation, while congestion management and allocation process updates bring greater precision and transparency to the market’s core operations.