The Dutch electricity sector - part 3: Developments affecting electricity markets

The figure below depicts the relationships between various variables and the electricity markets. In the subsequent paragraphs, we will provide an explanation.

Developments

Although electricity demand in the Netherlands has not increased in recent years, it is expected to do so in the coming years. In 2023, the net electricity consumption in the Netherlands amounted to 109 terawatt hours[1] (TWh, or one billion kilowatt hours). According to the Netherlands Environmental Assessment Agency (PBL), in its 2023 Climate and Energy Outlook (KEV), this consumption is projected to increase to a range of 138 TWh to 159 TWh by 2030. Looking at capacity, currently peak demand stands at approximately 18 gigawatts (GW), with TenneT estimating 21.5 GW to 26 GW in 2030 in its 2022 Monitoring security of supply report (in Dutch).

Impact on electricity markets

The impact on electricity markets hinges significantly on what part of the future electricity demand is static or flexible. A (higher) static electricity demand can lead to high volatility on the spot market (which includes both the day-ahead market and the intraday market) because demand does not adjust significantly (if at all) to changes in electricity supply, which is increasingly weather-dependent. Static electricity demand can also contribute to feed-in congestion during periods of high solar and wind energy production. As a result, there is increased demand for local flexible power solutions in the congestion market. On the other hand, a flexible demand for electricity can contribute to offtake congestion. For example, when a large number of households in a street simultaneously charge electric cars and home batteries when electricity prices are low due to windy conditions. This flexible demand is mainly driven by wholesale and balancing markets, rather than by prices that indicate the available capacity of the electricity infrastructure.

[1] Source: CBS Elektriciteitsbalans; aanbod en verbruik.

Developments

A key variable affecting electricity markets is the amount of weather-dependent electricity generation relative to electricity consumption. This share has seen a significant increase over the past decade, rising from 5% in 2013 to 46% in 2023.[2] It is expected that this share will continue to rise sharply in the coming years, reaching approximately 73% to 90% by 2030[3], as the absolute amount of electricity generated from solar and wind sources will more than double (see Table 1).

[2] Source: CBS Elektriciteitsbalans; aanbod en verbruik.

[3] Figures in 2030 are based on: 35 TWh to 41 TWh of electricity from onshore wind and solar farms (PBL et. Al. (2023) KEV), 12 TWh from small-scale solar panel installations (PBL (2023) Monitor RES 2023), 15.8 GW of deployed offshore wind capacity (this is considerably less than the government's target of 20.5 GW by 2030. Apparently the PBL assumes that the full 20.5 GW will not be achieved by the end of 2030). This adds up to approximately 68 TWh of electricity production (assuming 4,300 full-load hours per year. This is implicitly considered in the letter to parliament regarding a supplementary roadmap for offshore wind energy by 2030'). Additionally, there will be 3 GW of offshore solar capacity, contributing 1.4 TWh to 3.5 TWh of electricity production (calculated based on a range of 1.5 GW to 3 GW installed capacity, with 935 full-load hours for floating solar PV and 1,170 full-load hours for sun-following solar PV on water).

Given that solar and wind power are not consistently available, it is essential to maintain sufficient dispatchable generation capacity within an electricity system. According to TenneT’s recent report on security of supply (in Dutch), this capacity is projected to decrease from over 22 GW in 2022 to 14.5 GW in 2030. This reduction is due to the decommissioning of gas-fired power plants for technical and economic reasons, along with the phasing out of coal-fired power plants starting in 2030 due to government policy. As a result, by 2030 the installed dispatchable generation capacity will be lower than the expected peak demand. This means that the Netherlands will become dependent on the supply of flexible capacity (such as by batteries) for security of supply.

Impact on electricity markets

A rapid increase of wind and solar power supply is leading to more hours with low or even negative electricity prices in the day-ahead market. At the same time, the decreasing amount of installed dispatchable generation capacity can actually result in an increased likelihood of moments with (very) high prices on the day-ahead market when little sun and wind are forecast. In addition, the demand for balancing capacity is rising. Wind and solar energy generation cannot be perfectly predicted, so even small deviations from forecasts can lead to significant imbalances. Furthermore, in the coming years, there will be less dispatchable thermal generation capacity (such as gas-fired power plants and thermoelectric power plants) available on the balancing markets, putting pressure on the price for upward balancing capacity.[4] Finally, an increasing concentration of wind turbines and solar panels in a given area could lead to local congestion and, consequently, greater demand for local flexible capacity.

[4] If there is an electricity shortage in the system, it can be restored by either producing more electricity or reducing electricity consumption. This is called upward regulation.

There are several forms of flexible capacity. We’ll discuss the most important ones. TenneT expects the total installed flexible capacity to increase from over 11 GW in 2022 to nearly 26 GW in 2030. However, it’s essential to note that the transmission system operator (TSO) assumes no grid congestion during this expansion.

Developments

Developments in demand response

The management of electricity demand using (price) incentives is called demand response. Many forms of flexible power fall under this category, including the use of batteries and electrolyzers.[5] However, in this article we’ll discuss these topics separately.

For many companies, it proves challenging to implement demand response. These difficulties arise from various factors, including organizational challenges, power grid congestion and Dutch transportation tariffs (more on this later). For example, a large industrial electric boiler can be utilized during periods of abundant (cheap) electricity supply, but such usage may require a larger transportation contract. Unfortunately, due to grid congestion, this option is not always feasible. In addition, switching to a larger transportation contract is more expensive, which can offset the relatively low expenses of flexible electricity consumption.

For households and other small-scale consumers, demand response for appliances such as heat pumps and electric vehicles is financially advantageous primarily when they have signed a dynamic electricity contract[6]. However, by the end of 2023 only 3% of households had such a contract.

In the coming years companies and households will increasingly install electrical appliances, such as heat pumps, electric boilers, batteries, charging stations, and solar panels. However, there is no legislation in the Netherlands that requires these appliances to be smartly controlled. As a result, demand response is expected to play a limited role in the Dutch energy system until 2030. TenneT estimates that there will be 1.7 GW of flexible capacity from industrial demand response by 2030. On the other hand, TNO’s report on the role of demand response indicates that there will be less than 0.2 GW of demand response by 2030, even including the flexible capacity supplied by electrolyzers.

Developments in batteries

Batteries, when used effectively, can help balance the electricity system and reduce grid congestion. They can be installed both "before the meter" (stand-alone) and "behind the meter" at existing end users. Stand-alone batteries are typically much larger than those installed behind the meter.

Previously TenneT expressed hope for at least 10 GW of large-scale battery capacity (before the meter) by 2030. However, in its new report, the TSO now indicates a total of only 2 GW, along with an additional 2 GW of large-scale batteries at solar farms. This is more in line with the expectations of CE Delft, which indicates that only 0.5 GW to 2 GW of batteries will be economically viable for deployment in balancing markets by 2030. Yet, that deployment remains a crucial part of the revenue potential of stand-alone batteries. Although applications for connecting large-scale batteries to the power grid have already exceeded 10 GW, Energy Storage NL reports that only a fraction of that capacity (250 to 350 MW) is currently operational in the Netherlands as of early 2024.[7] Meanwhile, several new large-scale battery projects have been announced, including Mufasa (364 MW, 1,457 MWh), Leopard (300 MW, 1,200 MWh), Holland Battery 1 (180 MW, 360 MWh) and Dronter Energie Opslag (200 MW, 1,600 MWh).

Besides stand-alone batteries, more and more companies (and to a lesser extent, households) are investing in batteries behind the meter. Part of this trend is driven by power grid congestion issues. Such batteries can be a solution for companies that cannot secure a larger transportation contract. Grid congestion issues are therefore likely to be a major driver of the proliferation of these type of battery in the electricity system in the coming years, even if the costs cannot be immediately recouped. Unfortunately, no one has insight into how many batteries have been installed behind the meter.

The bulk of batteries in the Netherlands consist of so-called two- or four-hour batteries. This means that they can absorb or release electricity at full capacity for two or four hours. As a result, they are less suitable for handling prolonged surpluses (for example, due to persistent strong winds in the North Sea) or shortages.

Interconnection developments

Interconnector capacity (electricity connections with other countries) is expected to increase from over 9 GW in 2022 to 12.8 GW by 2030. This will allow the Netherlands to export more electricity when supply exceeds demand and import more when the opposite is true. However, the key question is whether our neighboring countries are eager for our surpluses, or whether they can actually assist us when we need additional capacity. After all, they are also increasingly deploying weather-dependent generation capacity and phasing out dispatchable capacity. TenneT expects that the surpluses and shortages in the Netherlands will to a large extent coincide with those of Germany, Denmark, and Belgium, and less so with those of the UK and Norway. Interconnector capacity with the latter two countries in particular can therefore provide flexible capacity at the right moments.

Curtailment developments

The downward regulation of renewable electricity production, also known as "curtailment," has become more common, especially during periods when electricity supply exceeds demand. Recently, if not already suitable, existing onshore wind and solar farms have been adapted for curtailment. In addition, there is a small group of households (with dynamic contracts) that manually or automatically turn off their solar panels when appropriate price incentives are in place. However, most rooftop solar panels are "dumb" and not smartly controlled based on price incentives or available grid capacity. In some cases, however, solar inverters will shut down due to excessive grid voltage, which is also a form of curtailment.

Developments in P2H and P2G

Electrical energy can be transformed into thermal energy (heat) and chemical energy (such as hydrogen). This process is referred to as “power-to-heat” (P2H) and “power-to-gas” (P2G). P2H can be integrated with district heating networks, and there are already specific plans for this in the Netherlands. However, the development of new district heating networks and the sustainability improvement of existing ones face challenges, in part because of uncertainties about future laws and regulations.

Although the Dutch government aims to have 4 GW to 8 GW of installed electrolysis capacity by 2030, P2G is not yet widely implemented at this time, and only one party has made a final investment decision to do so. Therefore, we expect the flexible capacity of P2G and P2H by 2030 to be limited. However, TenneT expects 3 GW of P2G capacity and 3.3 GW of P2H capacity.

Developments in electrification of mobility and V2G

'Smart' charging of electric vehicles can also provide flexible capacity. ElaadNL estimates that by 2030, there will be approximately 1.6m to 2.1m electric passenger cars in the Netherlands, plus other electric vehicles such as buses and delivery vans. TenneT expects that this will result in a flexible capacity of 0.5 GW by 2030. While more and more parties are enabling smart control of private charging stations, it is not yet a widespread practice. Also, not all public charging stations and charging hubs are smart. However, there has been increased attention for this issue recently, partly due to current congestion problems. We therefore expect this development to accelerate toward 2030.

The injection of electricity into the grid by electric vehicles, also known as ”vehicle-to-grid” (V2G), has been a long-standing promise. In practice, however, it occurs very rarely because most vehicles and/or charging stations are not suitable for this. Several car manufacturers will soon be introducing models that can handle V2G. Nevertheless, a number of barriers related to technology and regulations may make large-scale V2G implementation by 2030 challenging. Therefore, it remains uncertain how much flexible capacity from V2G will be available in 2030.

Impact on electricity markets

Toward 2030, the supply of flexible capacity will increase. The supply of downward capacity is expected to be significantly higher than the supply of upward capacity, due to curtailment. A larger supply of flexible capacity has a dampening effect on the volatility of electricity prices in the spot market, because it helps aligning anticipated electricity demand and supply. Moreover, a greater supply of flexible capacity also has a stabilizing effect on prices in congestion and balancing markets.

However, it is uncertain whether the increase in the supply of (the right form of) flexible capacity will be sufficient to keep up with rising demand for it. This is particularly true for upward capacity in general and for coping with longer periods (days to weeks) of little sun and wind in particular. For this purpose, upward capacity that can be deployed for longer periods of time is necessary. The current battery technology (including V2G) and demand response are less suitable for this, and interconnector capacity can only be used if our neighboring countries can export electricity at the right moment. Scarcity of upward capacity can certainly lead to high prices on the spot and balancing markets during such periods.

The congestion market will also benefit greatly from more flexible capacity. It is not only the quantity of flexibility that matters, but also the location. Currently, there is insufficient supply of flexible capacity in the congestion market, and it does not appear that significant improvements will happen in the short term.

It is challenging to precisely forecast how much flexible capacity will be available in 2030, because an increase in the supply of flexible capacity reduces the earning potential of existing and new flexible capacity. Indeed, more flexible capacity results in less price volatility in the spot market and lower prices in the congestion and balancing markets. This cannibalization effect can eventually hinder the supply of new flexible power – particularly that of stand-alone batteries.

[5] Electolyzers are devices that use electricity to split water (H₂O) into hydrogen (H₂) and oxygen (O₂).

[6] A contract with hourly changing prices based on the day-ahead prices.

[7] Batteries larger than 1 MWh.

Developments

The Netherlands is facing significant power grid congestion issues. The most recent overview of the status of grids for large-scale consumer connections can be found on this map. Despite various action plans by the Dutch government and the Authority for Consumers and Markets (ACM) to address grid congestion, and despite record investments by grid operators to expand the electricity grid, the grid operators themselves indicate that the problems will persist for at least another 10 to 15 years. Until 2030, the issues are expected to worsen rather than improve.

Impact on electricity markets

Power grid congestion affects several other variables that ultimately have an impact on electricity markets. To begin with, grid congestion affects both the total and flexible demand for electricity. Due to the limited capacity of the electricity grid, end users find it more challenging to consume additional electricity and/or flexibly adjust their electricity demand. This can lead to increased price volatility in wholesale markets. On the other hand, grid congestion can hamper the supply of additional weather-dependent electricity production capacity, both in general and particularly during periods with high wind and solar generation. This, in turn, has a stabilizing effect on electricity volatility in the trading markets.

Furthermore, power grid congestion is a major driver for installing batteries behind the meter at wind and solar farms, and at companies that originally intended to sign a new or larger transportation contract. This battery capacity can often also be (partially) used for trading on the electricity markets. Finally, congestion issues directly impact the congestion market: increased congestion leads to greater demand for local flexible capacity.

Developments

In recent years, grid operators' tariffs have increased substantially. For small-scale consumers this increase ranges from 50% to 90% over the past five years, depending on the size of their connection and the grid operator. Meanwhile, the grid tariffs for large-scale industrial consumers have increased from a few euros per MWh in 2020 to EUR 18 per MWh in 2024.[8]

If the premise remains that grid tariffs must be cost-covering, tariffs will continue to rise in the long term, as grid operators are investing billions of extra euros in electricity infrastructure in the coming years. Therefore, this premise is currently under discussion. It is possible that in the future, part of the grid operators' costs will be covered from general government funds, which would alleviate grid tariffs.

Large-scale consumers that only supply electricity to the grid (such as solar and wind farms) are currently not affected: they do not pay transportation costs.[9] However, this exemption is under discussion, as there is no concrete proposal yet for introducing a so-called producer tariff. If such a tariff is implemented in the future, it could impact the development of new wind and solar farms.

Large-scale, stand-alone batteries do face challenges due to high grid tariffs. TenneT and the ACM are working on several proposals that could result in up to a 65% discount on transmission tariffs for parties directly connected to TenneT. This will make the business case more appealing. However, in their 2024 report on supply security monitoring, TenneT assumes that only 4 GW (2 GW stand-alone and 2 GW at solar farms) of large-scale battery capacity will be installed by 2030, and then they are already factoring in the application of these discounts on transmission tariffs.

In other countries, electrolyzers are often exempt from paying transportation costs. Therefore, it is more attractive, for example, to invest in P2G in Germany.

Large-scale consumers who want to electrify and flexibilize their energy consumption also face high grid tariffs. The tariffs also contribute to the closure or downscaling of large industrial companies that consume a lot of electricity. Thus, there is a relationship between grid tariffs, electricity demand, and the supply of flexible capacity from industrial demand response.

Impact on electricity markets

Grid tariffs indirectly impact the electricity markets because they currently hinder the electrification and flexibilization of energy demand, and they pose an obstacle to investment in large-scale battery storage and green hydrogen production.

[8] In addition, the so-called volume correction scheme (VCR) was abolished in early 2024. This scheme allowed certain large-scale consumers, who consistently consume a significant amount of electricity, to receive up to a 90% discount on their grid tariffs.

[9] Transportation charges are an important part of grid operators' tariffs for large-scale consumers.

While the Netherlands is gradually reducing its reliance on gas and coal-fired power plants for electricity generation, these plants still play a significant role in determining prices on the day-ahead market. This is because the most expensive plant deployed at a given moment determines the price at that specific moment. Therefore, even a sudden increase in natural gas prices still has a relatively large impact on future electricity prices.

After the natural gas price peaked at nearly EUR 350 per MWh in August 2022, it has since dropped again and is currently hovering around EUR 30 per MWh. On the long-term market, natural gas prices[10] are expected to remain at a similar level for the next few years. According to the International Energy Agency (IEA) in its most recent World Energy Outlook, natural gas prices in Europe are projected to decline toward 2030 due to an increasing supply of LNG.[11] PBL considers a wide range of possibilities, as reflected in table 2. Of course, unexpected (geopolitical) developments can suddenly alter this outlook.

Coal was relatively expensive compared to natural gas in 2023, resulting in limited deployment of coal-fired power plants. Expectations for future price levels vary widely. This makes it difficult to indicate how often Dutch coal-fired plants will be deployed in the coming years and whether they will be price-setting or not.

Besides the price of raw materials, the price of European emissions allowances also affects the cost of electricity produced from natural gas and coal. Currently this price hovers around EUR 75 per ton of carbon dioxide equivalent (CO2e).[12] PBL assumes that by 2030, this price will fall within the range of EUR 87 and EUR 149 per ton. With stable natural gas and coal prices, this implies a higher cost for electricity produced from these resources.

[10] Prices for cal-25, cal-26 and cal-27 for Dutch TTF natural gas futures on ICE Endex.

[11] Liquified Natural Gas. It is natural gas that can be delivered by ship.

[12] A CO₂ equivalent is a unit that quantifies how much the emissions of a particular greenhouse gas contribute to global warming. It is expressed in terms of the impact equivalent to one kilogram of CO₂.

Unlike some other European countries, the Dutch electricity sector relies more on the so-called “energy-only” principle than on a capacity market. This means that market parties receive less compensation for making production capacity available. Investors primarily need to recoup their money through the actual utilization of this capacity (i.e., by producing electricity).[13] However, in the long term, this approach poses risks to security of supply, as dispatchable, thermal power plants produce fewer hours of electricity per year due to the rise of solar and wind energy.

Therefore, it is crucial that investors can trust that governments will not intervene when prices are high. High prices, which can occur in extreme situations, may be necessary to make or keep certain production facilities profitable. The European Commission’s intervention in the electricity market in 2021 and 2022 in response to extreme price increases, has eroded this confidence.

The European Union is also working on reforms for the electricity markets.

[13]An exception to this are so-called black-start facilities. These power plants can restore an electric grid to operation to recover from a total or partial shutdown without relying on the external electric power transmission network. However, blackouts have not occurred in the Netherlands to date, so such facilities are expected to be rarely or never deployed. Nevertheless, the investment must be recouped. TenneT achieves this by compensating investors for providing black-start capacity.

The main variables and their direct impact on the different markets are listed in table 3. The table makes clear that there is much uncertainty regarding the future developments of electricity markets. Government choices, among other factors, have a significant impact. However, it is evident that there is a growing demand for (local) flexibility. Private individuals and businesses capable of adapting to this demand can benefit. Conversely, companies and private parties who fail to address this need may face higher costs for their electricity consumption. Therefore, it is essential to approach this with a strategic mindset.

The electricity sector is evolving rapidly. By 2023, half of the electricity produced was renewable. An increasing number of consumers are generating their own electricity, and electrification of transport and heating is also on the rise. All this has an impact on the load on power grids, the supply and demand balance, security of supply, and electricity prices. These developments present both risks and opportunities for electricity users. To better understand these risks and opportunities, RaboResearch is publishing a series of articles on the Dutch electricity sector. In the previous part, we discussed the different electricity markets. In this part, we provide an overview of the key developments that influence the electricity markets and explore their potential impact. One final part will follow.

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