The Dutch day-ahead top-bottom (TB) spread, TB2, has averaged €91k/MW/yr since January 2025, level with Germany and 69% above Great Britain. That spread stems from two price regimes set by solar and gas. Yet only 0.6 GW / 1.3 GWh of utility-scale BESS operates in the Netherlands today, against 7.6 GW / 12.5 GWh in Great Britain. Scaled for the country's peak demand, the battery fleet (MW) in the Netherlands is more than 4 times smaller than Great Britain.

The grid connection charges are one factor why the battery buildout lags. TenneT, the TSO in the Netherlands, charges €116k to €150k/MW/yr for import capacity, depending on voltage level. A battery has to pay that bill unless it agrees to a Time-Dependent Transport Rights (TDTR) contract which cuts the bill by up to 62%. In exchange, TenneT can impose restrictions with one day's notice, for up to 15% of the year.

If there's specific research you'd like to see on the Netherlands, reach out to the author: emiel@modoenergy.com

Key takeaways

• The Dutch day-ahead TB2 spread averaged €91k/MW/yr from January 2025 to July 2026, level with Germany and 69% above Great Britain. The spread is widening: €83k/MW/yr across 2025, €102k/MW/yr over the first seven months of 2026.
• The spread is driven by solar, swinging prices from a midday floor to a gas-set evening peak. Rooftop solar in the Netherlands is not exposed to day-ahead prices. That volume can push the market to the EU-wide floor of -€500/MWh.
• TenneT charges €116k/MW/year at extra-high voltage (EHV) and €150k/MW/year at high voltage (HV), regardless of location within the Netherlands. Both are charged purely on grid imports. This has been the main barrier to battery development.
• Time-Dependent Transport Rights (TDTR) reduce that bill by up to 62%: a 43% reduction from the contracted-capacity discount, plus a reduction of up to 19% from timing dispatch into the network's lowest-weighted hours.
• TDTR has been an attractive route for BESS to connect, with a buildout due to hit 4 GW / 14 GWh by 2028.

Grid connection charges have risen sharply, TDTR brings relief

TenneT's grid connection charges are the single biggest barrier to Dutch battery deployment. They more than tripled between 2021 and 2024, reaching as much as €116k/MW/yr for Extra High Voltage (EHV) and €150k/MW/yr for High Voltage (HV).

TenneT's grid has spare capacity most of the year, outside a handful of peak hours. In a standard contract, access is firm or year-round. The TDTR contract has offered an alternative since October 2025. It guarantees 85% of transport capacity across the year, and for the other 15%, TenneT can impose constraints with a day's notice. For this non-firm connection, TenneT will reduce the annual grid charge by up to 62%.

The TDTR contracts have proven attractive for BESS. The number of Dutch BESS projects has surged since 2025. The pipeline reaches 14 GWh by 2028, a more than 22-fold increase on the 620 MWh operational by 2024.

Today's fleet sits at 0.6 GW / 1.3 GWh across roughly 100 systems. Of this 600 MW, 26 sites are individually identifiable BESS sites, which add to 476 MW (77% of operational power), and average 18 MW. The rest are BESS sites < 7MW, likely colocated with demand or renewables, which Modo Energy does not currently track. Dutch batteries also have longer durations than their neighbours: the operational fleet averages 2.1 hours, against 1.65 hours in Great Britain in Q2 2026 and 1.5 hours in Germany in Q4 2025. That duration will only increase: 90% of the BESS MWh that will be installed by 2028 is 4 hours or longer.

Ask Ko: Compare the Dutch BESS buildout to other European countries

Contracted capacity cancellation and a reduced peak charge make up the 62% discount

Across Europe, TSOs apply four types of charges for a grid connection:

• Contracted capacity: a fixed annual charge based on the maximum capacity a user reserves at the connection point, in €/MW/year, whether or not that capacity gets used.
• Peak: a charge based on the highest power actually drawn or exported during a billing period.
• Volumetric: a charge per unit of energy transported, in €/MWh. Where TSOs vary this rate by time of day, it gives users a direct incentive to shift consumption or injection away from congested hours.
• Fixed connection fee: a flat annual charge for having a connection to the grid.

TenneT applies a contracted capacity charge and a monthly peak charge. Both fall entirely on the import side, while export carries no recurring charge at all. The discount through the TDTR contract comes from a reduction on both components.

The contracted capacity charge is the simpler of the two: with TDTR, it's cancelled out entirely. This provides a 43% cost reduction.

The peak charge works differently. Since 1 January 2025, TenneT weights the power peak by time-of-day before applying the max per month. Due to the time-dependent weights, a larger peak power in a low-weighted window can count for less than a smaller peak in a high-weighted one. During the summer months, April to September, this weighting factor caps at 0.8. With the TDTR contract, the peak charge still applies, just on 85% of the year's hours instead of all of it. This can lead to a lower weighted power peak, and reduces the peak charge to €44k/MW/yr for EHV and €56k/MW/yr for HV. This represents an additional 19% reduction in the grid charges.

Why are we seeing a growing queue, given such high grid charges?

The Dutch BESS pipeline keeps growing, yet grid connections are expensive. TenneT charges up to €150k/MW/yr, and even with a TDTR contract cutting that to €57k/MW/yr, the bill is still steep.

Compare that against Great Britain: Modo Energy's own 2-hour battery benchmark puts GB revenues at €88k/MW/yr since 2025. A Dutch-sized grid charge would make that business case fall apart.

Ask Ko: How does the GB 2h BESS revenue stack looks like?

But Dutch market fundamentals are stronger. Renewable and thermal sources drive Dutch electricity generation. While renewables average 49% and gas accounts for 35% in 2025, the actual mix shifts depending on the time of day.

The amount of solar and wind is what creates two extreme price regimes. With no solar and low wind, combined cycle gas turbine (CCGT) and coal set the price, at the marginal cost of burning fuel plus a carbon price. With high solar and high wind, the zero-or-negative-cost supply covers the entire 10 to 19 GW demand range, and the price falls with it. The Netherlands has interconnection with Great Britain, Norway and Denmark, but Germany and Belgium carry most of the capacity: 4-5 GW and 2-3 GW, against 2.4 GW across the other three. Both Germany and Belgium have their own solar fleets which generate in the same hours, so prices fall on both sides of the border at once and there is little room to export the Dutch surplus.

Ask Ko: What is the energy generation mix of Germany?

The chart below traces that stack hour by hour. Move the time-of-day slider to see which technology sets the price at each hour, and the gas price slider to see how a higher TTF price lifts the evening peak without touching the solar-covered midday trough.

Solar alone reached 19 GW at midday on 1 May 2026, and wind and solar together covered more than 100% of demand for 9 hours. Demand itself peaked at just 14 GW, at the same hour solar peaked, and gas and coal only stepped back in once the sun dropped in the evening.

That midday surplus turned the day-ahead price negative. It fell to -€499.6/MWh, very nearly hitting the EU-wide floor of -€500/MWh at that time. Prices only go that negative when nothing on the supply side backs off. That is what happened with the 12 GW of residential rooftop solar. Net metering nets what a household exports to the grid against what it imports, so rooftop solar keeps exporting regardless of price, even at that EU-wide floor, which is what pushed the price so low.

A Capacity Mechanism from 2028 strengthens the BESS buildout, and de-rating decides by how much

The Dutch government confirmed a market-wide Capacity Mechanism on 19 June 2026, with delivery from 2028. The de-rating methodology is still open. For batteries, that de-rating is the most important number in the design, because it converts installed capacity into the firm capacity an asset actually gets paid for.

Across Europe, 2-hour batteries carry de-rating factors between 0.14 and 0.44. This means that 2-hour BESS in the Netherlands of 100 MW can contract 14 MW to 44 MW of firm capacity. Four-hour systems can contract 28% to 67% of that 100 MW, so the pipeline's shift towards longer duration works in its favour.