Ralf Bischof, published in SOLARZEITALTER 2-2023/1-2024
This article was originally written in German and has been translated by EUROSOLAR.
Over seven percent of the yields from wind and solar installations in Germany are now being curtailed due to grid or market conditions. The use of these surpluses in the heating market are being prevented by a rigid system of network operators and fees. If these are utilised intelligently and dynamically, they can relieve networks and the electricity market with the provision of cheaper heating from renewable energy. Additionally, alternatives to the public network like direct connections must be made possible. As with the establishment of oligo political power plant sectors through feed-in laws, this would mobilise new actors and innovations.
In 2023 around 14.5 billion kilowatt-hours (kWh) of electricity were curtailed from solar and wind installations, according to the numbers from the German transmission operators and the Bundesnetzagentur (Federal Network Agency). That amounts to more than seven percent of the yields from these installations. The reasons for that are grid bottlenecks and temporary oversupply on the electricity market. In comparison to the previous year, there has been an increase of lost volumes by 18 percent – although the yields have only increased by nine percent. In 2022 there was already 12.2 billion kWh, of which over 65 percent (8.0 billion kWh) was regulated by the so-called Redispatch 2.0 (formerly: feed-in management). The smaller part was switched off by the marketers due to negative spot prices.
Grid regulated in addition to market regulated surpluses could easily be avoided. According to statements of the Bundesnetzagentur, in 2021 around 73 percent of outages were caused by bottlenecks in the transmission grid. Through incorporating the shared grid, electricity may also be transported to a customer. Even when the shared grid is overwhelmed, installations can almost always find consumer who may use the electricity effectively, as long as it is not transported to higher grid levels.
Negative prices in short-term electricity trading are also no reason to restrain installations. In these times, it would be very easy to replace fossil fuels for heat generation with electricity. Had one used the lost wind and solar amounts from over 12 billion kWh in 2022 for the generation of heat close to installations, natural gas to the value of 1.5 billion Euros would have been replaced.
Why is this use, known as “utilising instead of switching off”, hardly ever applied? The main reason is a legally grounded system of network operators that is still portrayed as dysfunctional, as the share of renewable energy (EE) now accounts for over 50 percent of electricity generation. This is exacerbated by levies and surcharges, which are often directly linked to the grid fees.
Alongside the aforementioned financing function, the grid fees should send the right price signal, so that the use of the grid by consumers matches shortages. If the grid is heavily used while there is a considerable level of EE feed-in, use in this region should be encouraged in terms of price. Conversely: If there is high demand from users, the grid use should become more expensive. The grid use changes from hour to hour and is not dependent on the yearly hours of use – the ratio of energy consumed (kilowatt hours) to the maximum power consumed (kilowatts). The usage hours are, according to the legal electricity grid regulation, the deciding criteria for determining the average grid charge of a consumer. Since the liberalisation of the electricity market at the end of the 1990s, nothing has fundamentally changed. The reform backlog is enormous. Adjustments were only made in homeopathic quantities and for a limited period (e.g. for storage facilities). With one exception: electricity intensive enterprises, whose usage time can exceed 7000 hours, will be rewarded with grid fee discounts of up to 80 percent. That is exactly the opposite of the necessary flexibility!
Absurd: highly regulated electricity prevents profits and relief!
Especially extreme are the implications for the network systems for the above described surpluses. These apply only in a few hundred hours of the year. Negative prices in the stop market were only 301 hours in 2023, for example. In 2020, it was 298 hours.
If grids are calculated to use less than 2500 hours per year for passing through, there must be very high labour costs per kWh in the bill. To supply a commercial customer with medium voltage, the majority of grid operators charge six cents per kWh (ct/kWh) and more. This alone clearly goes over the negotiated trading price for natural gas: at the beginning of 2024 the appointment price for strip deliveries was negotiated at around 3 ct/kWh for the next years, with a downward trend. Even in the hours with an oversupply of EE-electricity and an applicable electricity price from zero, cannot possibly realise a cost covered business model.
Particularly absurd is the fact that the regulated electricity as a result, does not ultimately flow to customers and the network operators do not make revenue. If one would- and should- be allowed to negotiate like a free salesperson, the prices in these situations would noticeably decrease. It is preferable to have a small proceed than no proceeds at all.
A simple regulatory solution would be to cap the energy price in the event of a redispatch caused by upstream grid areas at a low value of around a single ct/kWh in order to encourage the use of otherwise restricted electricity before the grid bottleneck. Additionally, the capacity price could be reduced proportionally over time, or through a promised pay-back. As a result, all users would be significantly relieved: for one, missing compensation payments for the redispatch to EE-installations would be eliminated. On the other hand: network operators could benefit from more income from the additional loaded electricity that sinks the specific prices.
In this context, however, it should not remain unmentioned, that many grid bottlenecks could already be avoided by optimising the grid. The 2022 report of the Bundesnetzagentur into the state of building shared networks shows that technical measures like landline monitoring, regulated area network transformers or a voltage and reactive power management are not implemented by the vast majority of network operators, although they are generally cheaper and quicker to use than those from the network expansion. What remains unmentioned in the report is the likely more effective measures of the so-called curative network management. With the redispatch no one will have a serious network overload, but rather always based on a fictitious overload in the so-called n-1 case.
The grids are never utilised to more than 50 to 70 percent of their capacity – additionally, they will be preventatively curtailed. Alternatively, wind and solar parks can use a curative (or reactive) grid security management system. Further, the yield installations are only curtailed when a moderate oversupply is foreseeable (a lot of wind and sun and equipment failure).
Due to thermal inertia in cables and transformers, little time is available. For wind and solar installations, a complete shutdown in less than a minute is technically not a problem. A targeted implementation on a few large transformer stations, which predominantly serve to store electricity from renewable sources, could significantly reduce lost energy in the short-term.
Cheaper green heating with dynamic grid charges
The above outlined dysfunctionality does not only match with the grid bottlenecks and negative market prices, but also to periods with weaker electricity prices. In general it applies that if a single kWh is greener than a single kWh of natural gas or oil, these fuels should be replaced by electricity. It can evidently provide greater benefits. The sector coupling sinks emissions and costs. It additionally has a stabilising effect of the market values and the adoption of EE-production. This also results in a reduction of the Erneuerbare-Energien-Gesetz (Renewable Energy Act) costs carried by the taxpayer.
As wind and sun fluctuate, dynamic and especially variable grid fees are needed. If one connects the grid fees with short-term prognoses of the grid load, one can vary the charges based upon time: previously the grid operators published the prices for every quarter of an hour the day before. Electricity deliveries and installation operators can read this data electronically and agree an optimal mode of operation and trading strategy. Surpluses will automatically be reduced and only in exceptional cases will the grid operators have to take control.
As the grid situation can vary regionally, dynamic grid costs implicitly lead to locally variable prices. To this effect, the differentiating marginal costs of an avoided grid expansion in one area should be taken into account. In extreme cases, the grid operator could even offer negative prices, so to avoid investments in a grid that is overloaded due to strong EE-yields. The local use of feed-in peaks is plainly cheaper than evacuation after a few hours. This intelligent peak capping is sensible from a macroeconomic perspective, it is however missing a steering instrument for the grid operator. With dynamic grid fees, usage could be incentivised at the right times. This would additionally mean that regions with a high EE-share would profit and not have to pay for transport to other regions with their own grid fees.
The necessity for timely and orderly grid fees is not a new realisation, but so far it has not been implemented. As explained above, network operators are prohibited from deviating from the regulated system. It is not understandable why they should not offer flexible fees on a voluntary basis in addition to the regulated fixed fees. Of course only customers for whom the flexible model offers advantages, would use it. That is however, not cherry picking to the detriment of other grid customers. In so far as the incentives are correctly balanced, the future grid expansion will be avoided and the existing grid will be better utilised. Further, new electricity applications in sector coupling are incentivised, which create additional revenue for the network operators. In every case, all grid customers will profit.
One first step in the direction of flexible tariffs has been taken by the Bundesnetzagentur, with the amended application of the § 14a Energy Economy Act on the grid oriented control of consumption facilities. The authority is clearly falling short, however. For one, only low voltage is addressed. High flexibility could potentially be utilised very quickly, especially for customers in the middle voltage range (industry, hospitals, spas, etc.), and simultaneously an essential technical pre-requisite already exists with smart meters (registered load profile measurement) that have long been established. Moreover, the restrictions on specific types of consumers, like the necessity for charging stations for electric cars, warm pumps and batteries, are misguided. For example, direct electric warmth generators that are not covered, like heating rods and electric boilers, may also use the surplus electricity described above as “fuel savers” in conventional heating systems. The investments in warm pumps or electric storage units are not economically sensible for just a few hundred hours of use per year. There is therefore a fear, that the electrification of traffic and the heating market will be made easier, but without a significant contribution to “use instead of powering down” being achieved.
Direct deliveries without grid utilisation
A short-term solution to the dilemma of the dysfunctional grid costs is the direct delivery of electricity without using the grid. Even in the long-term, the use of electric connection infrastructure of EE-installations for the supply of neighbouring users is economically sensible. This relieves the public grid, both at the feed-in point as well at the consumption point and can be used by other grid customers.
Example calculations show that up to two thirds of the usage of an industrial area may be covered through directly delivered wind power [see https://www.lee-nrw.de/data/documents/2023/12/06/572-65705d9393092.pdf]. The targeted use of electricity in times of strong wind for power-to-X applications and storage units can result in even higher shares being achieved.
There are only two means of which to supply electricity to third parties outside of the immediate vicinity without using a grid, which is always subject to grid fee regulations: within the so-called customer installations (previously also known as Area Networks) or via direct connections. Customer installations are however spatially restricted and are therefore hardly viable for the greater distances from wind or solar parks to potential users. Direct deliveries have so far been defined extremely restrictively by German authorities and courts. Many EE-installations are not allowed to feed-into the grid and many customers are not allowed to be connected. To this effect, the further passing of electricity from the grid – as a supplement to electricity drawn directly out of EE-installations – is seen as problematic. An economically viable full coverage with high availability cannot be realised this way.
Make new actors and innovations possible!
The Stromeinspeisungsgesetz (Electricity Feed-in Act) and Erneuerbare-Energien-Gesetz (Renewable Energy Act) were passed in 1990 and 2000 respectively, although many EE-installations were technically not yet prepared and were relatively expensive. The intention was to bring in new actors – beyond the established power plant operators – to use and improve this technology to make it possible. That is because only these new actors had any real motivation.
This philosophy of facilitation is what we now need in the area of electrical infrastructure. Whoever produces EE should also be able to bring it to customers. Trade and distribution are one thing, but physical delivery is also needed. There is no logical reason why only the operators of general supply grids should be able to claim a mandate for this. Direct deliveries should be made much easier by legislation.
A close consideration shows, that the often employed arguments against direct connections from “cherry picking” to “uncontrolled growth” to “the grid is a natural monopoly” do not go far. It indicates a lack of imagination and the protection of established interests. If today, in the underground of cities and villages there are not only the grid operator’s electricity cables, but also connection cables of decentralised providers and users, drinking water, water connections, heating pipes, gas pipelines, copper and fibre optic cables for communication, why should an additional direct line from producers to consumers endanger an abstract ‘monopoly’ or lead to ‘uncontrolled growth’? A supply solution that is favourable for suppliers and customers due to geographical proximity is not “cherry picking”, but rather an economically sensible solution in a competitive market. Who would want to deny a shop the opportunity to set-up where it can expect the most customers, even if that means a minimal drop in sales for department stores?
After all of the experience in the production and usage of installations to get yields of electricity from EE sources, we may also expect many economic and technical innovations in the physical delivery from new actors. These innovations would surely be adopted by the established grid operators, in so far as a modern regulation allows them to do so. The winners will always be the users.