What’s in store for Dutch batteries?

As an inhabitant of the Netherlands, I experience that Dutchies are often stereotyped as frugal (some would say ‘greedy’ – the expression “going Dutch” in English describes paying for your share precisely and not one cent more) and the Netherlands is predominantly seen as a trading nation. Therefore, one might expect that the business of buying goods at low prices and using or selling at a later moment when prices are higher, fits right up our alley. Yet, when it comes to storing electricity, the Netherlands lags far behind its neighbours.

However, recent developments with regards to policy, targets, and costs of battery storage could be a gamechanger for the sector. So, we thought it was time to look at what’s going on in this small, energy-intensive country at the North Sea and if there are lessons to be learned for other storage-deprived countries. Will the looming changes be sufficient to catch-up and reach the ambitious targets?

Storage market NL

At the end of 2022, according to Dutch statistics bureau “CBS”, there was approximately 145 MW of battery capacity connected to the Dutch grid. This consisted mostly of 1h batteries, and predominantly large-scale (>1 MW) batteries[1]. As a few large projects have come or will come online during 2023 (Semper Power plans to commission 60 MW), we estimate this will be around 200 MW by the end of 2023.

Besides the many parties who originally developed solar parks that showed an initial interest in storage, there are some developers on the market that focus purely on grid-scale batteries. These include Giga Storage, Semper Power, and Lion Storage. All these developers together have an impressive pipeline of projects of but they have so far struggled to get real traction in the market (the reasons for which are discussed below).

At the same time, grid operators indicate they need storage to relieve the grid and solve congestion and are increasingly pushing the government to come up with solutions. TenneT (the Dutch Transmission System Operator(TSO)), for example, recently announced they expect to need 9 GW of storage by 2030.

We’re not the ones doing the maths here for you (we trust you’re all able to do that quite well yourselves), but it seems to us that’s a rather big gap between the current installed capacity and the required capacity by 2030 (200 MW vs. 9 GW). Nonetheless, the lobby of has successfully managed to create a sense of urgency among the relevant governmental bodies who have now announced policy changes.

The question remains whether these changes will lead to a sufficiently attractive and financeable business case for storage in the Netherlands. To assess that, and to let you form your own opinion, we need to explain what’s really hampering the Dutch storage market.

Revenue model for storage projects

Historically, developers in the Dutch renewable energy space have been used to steady and predictable revenue streams, if not due to the stable SDE support mechanism, then because electricity prices in the Netherlands have been stable and predictable. There are many reputable market advisors willing to tell you whatever fortune you’d like to hear.

However, the revenue model for electricity storage is less straightforward. To boil it down, storage assets try to optimise their net revenues by being deployed across the different markets that are available to them. For the Netherlands, these markets are: the day-ahead and intraday market, balancing and ancillary services (FCR and – the latter is still theoretical due to technical requirements, which are still hard to meet for most storage assets) and congestion (GOPACS[4]) markets.

Some other countries (e.g. UK, Belgium) have a capacity market in addition to the previously mentioned markets which can further underpin baseline/downside revenues, but so far such a market is not available nor foreseen in the Netherlands.

Most advisors agree that by optimising your trading strategy across these markets – i.e. always choosing the most profitable one for a particular moment in time – electricity storage can be made profitable. However, none of these revenue streams is certain and stable, and forecasts are harder to make as a lot will depend on how well the asset is operated.[5]

That brings us to the challenge of financing these projects.

Financing of NL storage projects

The first storage developers expected to apply a simple copy-paste of the renewables business case to attract financing. Aware of the fact that financiers dislike the whimsical nature and high level of uncertainty of storage revenues, they looked for tolling agreements with traditional offtakers to secure their revenue streams. The offtaker would typically operate the battery and, net of operational costs, pay a floor price to the project. This would potentially be combined with some form of upside sharing. The floor price would be enough to finance a large part of the battery and a similar division of financing sources (debt/equity) as what existed for solar projects (roughly 90/10) was applied. Or so the thinking went.

However, with only a limited number of parties are able and willing to offer a ‘significant’ floor price (mainly Essent, Eneco and Centrica – the latter withdrawing this service from the NL market a few years ago), the competitive tension was much lower than what parties were used to in offtake-sourcing for ’traditional renewables’, and soon the offtakers exceeded their risk budget for offering significant floor prices, leaving storage revenues for developers either certain but (too) low to base a business case on, or mostly based on upside sharing and thus uncertain and risky.

As financiers are often able to finance storage but predominantly on certain cashflows (and for uncertain cashflows with a huge discount), floor prices formed the main revenue stream underpinning debt capacity. Unfortunately, floor price levels that are currently being offered do not come close to providing a solar PV-like debt portion, thus increasing the need for equity funding significantly. The original solar developers often struggled with the required liquidity to fund ca. 50% of their storage project capex. As a result, developments were paused, while developers started to team up with large investors to increase their liquidity. Nonetheless, even with sufficient equity the storage business case is not a given, especially when looking for some form of stable double-digit returns often required for the large amount of equity being deployed.

Still, developers hope to increase the amount of debt in their projects or increase returns to attract more equity. The revenues are difficult to structurally improve on, but on the costs side, improvements may now be more realistic.

Operational costs and grid transport tariffs

‘Traditional’ maintenance costs are relatively low, although they partially depend on the chosen trading strategy. The real burden is mostly high (and increasing) grid transport tariffs, due to ever-increasing costs to maintain and extend the grid, which grid operators are passing on to consumers. For the country’s biggest offtakers (connected to the 220-380 kV grid), grid tariffs have increased by a factor 9x since 2018. However, some changes have been announced that may reduce this burden somewhat.

Due to the changing use of our electricity grid, new locations for generation (and sometimes demand), and overall increasing electrification of society, the electricity grid needs to be reinforced in many locations. That will take years, and in the meantime, we’re stuck with a less-than-optimal grid and often congested areas, preventing generation assets and consumers from obtaining additional grid capacity or connecting to the grid at all. The ongoing and foreseen grid investments translate into increasing tariffs for use of the grid, which in the Netherlands is paid for by the consumers (different philosophies for this can be found in different countries, e.g. in the UK the producers pay the grid costs).

For a storage business case, these costs can go up to 80% (!) of the opex according to branch organisation Energy Storage NL. As an example, with the grid tariffs for 2023 of the Dutch TSO, TenneT, a 100 MW battery connected to the high-voltage grid pays ca. EUR 10 M of grid fees. The rest of the operation costs are in the range of EUR 3-4 M (…), so you can imagine the strain this puts on the business case.

Neighbouring countries have a completely different approach to this[7]:

1. UK; The original generator pays the grid fees
2. BE; Storage assets are exempted from grid tariffs for the first 10 years of operation
3. DE; Storage assets are exempted from grid tariffs for the first 20 years of operation

This results in great outcry among Dutch storage developers, demanding to align the policy more with one of these more favourable countries.

Is change around the corner?

One might wonder how we’re ever going to achieve even 1 MW of additional storage capacity in this grid congested country, but luckily, it’s not only doom looming on the horizon.

• Flexible grid tariff discount: Recently, the governmental body for market regulation (ACM) published a study to the grid tariffs. They conclude that a lower grid tariff for storage is a suitable instrument to stimulate flexibility in the energy system. ACM also conclude that a lower tariff purely for storage assets is undesirable, as other solutions should be rewarded equally for offering such services from a non-discriminatory perspective⁷. Subsequently, grid operator branch organisation ‘Netbeheer Nederland’ has made a time-dependent grid tariff proposal to the ACM. This would allow the grid tariffs to be reduced up to ca. 65%[8]^, [9], depending on the consumption/charge and generation/discharge behaviour (i.e. discount increases if congested moments – hours with low demand and/or excess production –are avoided). Unfortunately, this is only proposed for the high-voltage networks for now as grid operators need to get more experience in how this would work. Even then, according to Energy Storage NL, this is not nearly enough, referring to an estimate of EnAppSys that this will only render 1.7 GW of additional storage projects economically feasible by 2030;
• Congestion management contracts: Distribution System Operators (DSOs) are releasing their first transport capacity contracts which reduce the contracted power grid tariff whilst constraining the battery to be congestion neutral. In one example, this means a 15% reduction in transport capacity (for offtake) whilst receiving a 30% discount. Additionally, grid operators have announced that they will organize flex tenders to incentivize batteries and electrolysers on strategic locations in the grid[10];
• High FCR prices: Volatile prices show that potentially significant revenue upside can be generated. End of October 2023 and beginning of November 2023, there were some crazy spikes in the short-term flexibility market for FCR services. For four consecutive hours, TenneT paid 78 kEUR/MW, for in total 34 MW, amounting to a staggering EUR 2.6 M if you offered your storage facility on the FCR market[11]. Earnings over 2023 on the FCR market alone could go up to EUR 200 kEUR/MW (assuming 100% bidding on the FCR market). It should be noted though, that the Dutch FCR market is quite volatile compared to neighbouring countries with more storage capacity deployed, and capacities for which such prices are paid remain limited (think along the lines of the mentioned 34 MW…). More generically, it can be expected that also among storage assets a level of self-cannibalisation will occur, reducing the chance of such extreme price levels, on any market where storage assets are deployed. This could well have been a one-off black swan risk, and not something that storage developers should structurally bet on;
• Storage subsidy: . Until this time, many questions remain such as ‘will this be a CfD with a floor, or something similar to the existing NL support scheme for renewables?’, ‘can the subsidy be used to raise senior debt?’ and ‘do the storage and generation asset require to share a grid connection to be applicable for this support scheme?’. In the meantime, in Spain the latest storage subsidy seems to have been quite successful, so perhaps policymakers should take another look at what has been done over there[14].

Although there seems to be momentum now, the new incentives might prove insufficient to combat the ever-increasing grid tariffs. As many Black Friday advertisements have taught us: A 50% discount is nice, but rather meaningless if the original price just doubled.

It is apparent that the fast roll-out of intermittent renewables puts a strain on the historically inflexible design of the electricity grid. Build-out of grid capacity alone will not be sufficient, and new sources of flexibility are indispensable as spinning inertia and adjustable generation assets (mainly large gas- and coal plants) phase out. None of the proposed changes in itself seems likely to lead to a drastic change in the storage market, but perhaps the combination of above factors will tip the needle. Some further refinement of policies is likely required, though, and policymakers should pay close attention to creating a stable and financeable business case for storage assets if they want the market to take its responsibility here. Many neighbouring countries are showing that it is possible, as investments in storage assets are growing rapidly.

Despite a still challenging environment, let’s hope we manage to accelerate the much-needed build-out of significant capacities of storage assets. In any case, it seems as if some developments are pushing in the right direction and perhaps the Dutchies will muster the courage (i.e. give in to our frugal nature) to get our small rabbit-like country towards a fully charged Duracell action-figure.

[1] CBS, November 2023

[2] Stratergy, March 2023

[3] Grid balancing markets ‘Frequency Containment Reserve’ and ‘automated Frequency Restoration Reserve’, quite well explained by TenneT.

[4] Market platform – collaboration of Dutch grid operators – to reduce capacity shortages in the electricity grid (congestion).

[5] Cost savings, e.g. because connected parties can suffice with a lower capacity grid connection, or for behind‑the‑meter solutions, are not taken into account.

[6] Comparing the ACM regulated tariffs of 2018 with those of 2024

[7] ACM, March 2023

[8] ACM, October 2023

[9] Netbeheer Nederland, November 2023

[10] Solarmagazine, October 2023

[11] Stratergy, November 2023

[12] CE Delft, September 2023

[13] Minister for Climate & Energy, October 2023

[14] El Periodico de la Energeia, November 2023