The Power Grid of the Future - Ready for 80% Renewables?
With the so-called "Easter Package", which was adopted in the spring, the German government is getting serious: 80% of electricity consumption in Germany is to be generated from renewable sources by 2030. This significantly raises the previous target of 65% by 2030. By comparison, the actual share of renewables in 2021 was around 42%. At the same time, there is agreement that electricity consumption will increase significantly in the next few years - this is clearly reflected by trends in the mobility turnaround, the heat turnaround and the decarbonization of industry.
So all in all, we're talking about more than doubling the share of renewables in Germany within the next seven and a half years (by 2030) to achieve these goals. And aren't we just painfully seeing how - exacerbated by the lack of Russian gas supplies - the electricity market is already facing a test of endurance? (On current developments, see our article Large-scale battery storage as a key technology for the energy transitionin which we use the example of Whit Monday, June 6, 2022, to shed light on what awaits us in the energy market in the coming years).
Let's assume at this point that in the next few years we actually manage to defy the strained supply chains, resolve the conflicts between tidal flats and wind power, between solar energy harvesting and agriculture, and actually build the enormous amounts of renewables. Aren't we then faced with the fundamental problem that the power grids are not even available to carry away the excess power that is being generated? After all, the costs for grid and system security measures due to congestion on the power lines were already a whopping 2.3 billion euros in 2021, with an upward trend. Behind this figure are not only costs for the Redispatch conventional generation plants, especially to alleviate the bottleneck between northern and southern Germany. No, renewable energies were also forcibly shut down on a large scale to alleviate the bottlenecks both on the electricity highways of the transmission grid and on the electricity "federal highways" of the distribution grid.
In this way, nearly 6 TWh of renewable electricity production was curtailed in 2021, which still represents nearly 3% of total renewable electricity production.
With the ambitious expansion targets for 2030, rising electricity consumption and the bottlenecks already occurring today, the power grid of the future faces the major challenge of preparing for the massive increase in load within just a few years.
Why the current measures in the power grid are not sufficient for 80% renewables
The legislature recognized the seriousness of the situation some time ago and took countermeasures with the 'Grid Expansion Acceleration Act' (NABEG), which came into force in 2019. As a central element, the approval procedures for new construction and optimization of power lines were simplified there, which should lead to an acceleration of grid expansion. It is questionable, however, whether this acceleration will be sufficient to achieve the ambitious goals, as the implementation time for major grid infrastructure projects - even if everything goes smoothly in the approval process - should not be underestimated. For example, the grid operator TenneT is talking about completing the Elbe crossing - a 5-kilometer-long and 20-meter-deep tunnel under the Elbe River - by 2028 as part of the major north-south route 'SuedLink', even with the new requirements of the NABEG, if everything goes according to plan. Other projects are doing similarly. The consensus among experts is therefore that grid expansion will continue to lag behind the expansion of renewables in the medium term, so further measures are needed to achieve the ambitious targets.
For example, the NABEG also creates new opportunities for grid operators to include additional plants in the "Redispatch" process of the realignment of power generation to adapt to grid conditions. Under the umbrella term "Redispatch 2.0," from October 1, 2021, instead of the previous 80 or so conventional power plants across Germany, over 80,000 plants are now included in redispatch, including predominantly medium-sized renewables with a Powerover 100 kW, which until now could only be shut down via an emergency mechanism called 'feed-in management'.
But here, too, there is a big catch: it is true that Redispatch 2.0 enlarges the toolbox for grid operators, who now have a more powerful, well-plannable procedure for grid stabilization. But in many cases, the renewables used for grid stabilization are not actually switched off, but rather added to the grid. In this way, the grid can technically cope with a larger volume of shutdowns, but the overall absorption capacity of renewables is not increased. As a result, it is to be expected that large parts of the renewable electricity will continue to be shut down instead of being used in regions with high congestion. This contradicts the goals of the energy transition and sustainable solution options seem to be scarce.
How can the grid problems be solved ?
Price signals in energy markets are a powerful incentive to adjust behavior in the electricity market. At present, for example, we are observing massively increased price peaks, as the market is dominated by renewables in the sunny midday hours, while expensive conventional power plants have to be activated in the evening. Plants that can store the electricity during the day and withdraw it in the evening sometimes achieve high profits and at the same time help to dampen the price peaks. Such Energy Storage have a positive effect on the electricity market and provide increased stability.
However, if we are dealing with local grid bottlenecks, the incentives unfortunately do not yet work. We have a uniform electricity price in Germany, and whether the electricity is stored in Flensburg or in Füssen plays no role in the market price and the potential profits. In the future, however, markets will also play a decisive role at the local level. So-called "flexibility markets" have the potential in the future energy system to decisively improve the interaction between market and grid. The introduction of flexibility markets was adopted throughout the European Union as part of the so-called "Clean Energy Package" in 2019 and will be transposed into national law by Germany in 2021.
The essence is that the current system underlying the redispatch or Redispatch 2.0 described above is changed from a cost-based system to a market-based system. Flexible resources can then compete on price for the cheapest removal of a network congestion, rather than receiving predetermined compensation on a cost basis. In addition to conventional and renewable generators, which are already included in the current, cost-based' Redispatch 2.0' regime, electricity consumers and storage facilities (note: storage facilities shift consumption according to the EnWG amendment of July 2022 and are neither generators nor consumers) can then also assist in removing congestion. And in case of doubt, they do so more cost-effectively than the conventional or renewable alternatives. As a result, system costs are reduced, renewable curtailment is avoided, and innovative approaches to providing local flexibility are encouraged.
How can local markets solve our grid problems in practice?
In practice, a storage facility would offer a certain price, for example, in order to relieve a bottleneck due to renewable surplus in a certain region. It can do so if it has been previously discharged and if it is positioned at a point in the grid that is in the direction of power flow "upstream" of the critical congestion point. The grid operator can then compare this price to the costs that would be incurred by shutting down renewables - after all, renewables are entitled to reimbursement for lost marketing revenues. However, it would be quite possible for the storage facility to undercut these costs. After all, instead of shutting down the plants and thus destroying the electricity, the storage system can postpone generation until a later point in time when the grid is able to absorb it. High profits beckon especially when electricity is particularly scarce and expensive. For example, if the sun shines during the day and photovoltaic power clogs the grids, a conveniently located storage facility can solve this problem at low cost and absorb the power. It then benefits additionally when it sells the electricity on the market at higher prices in the evening, and as a pleasant side effect, no renewable energy has to be destroyed.
In the long term, such revenue opportunities will lead to locating storage facilities preferringly in regions with more serious grid bottlenecks for economic reasons alone - because there they can generate additional revenue by avoiding network bottlenecks. In this way, sensible investment incentives are provided for storage facilities where they are most urgently needed. The total cost of the system is thereby reduced, because from the grid operator's point of view, the remuneration for the storage facility - despite profits - is still lower than for the curtailment of renewables. And if the storage facility has overly high price expectations, it will go completely empty-handed and the grid operator will resort to shutting down renewables. The electricity consumer cannot lose out, as the grid costs do not rise, but can fall significantly. This is then reflected in the electricity bill.
Flexibility markets therefore offer great potential for managing existing grid bottlenecks more cost-effectively and thus supporting grid expansion. In addition, better utilization of the existing grids means that fewer renewables have to be switched off - all in all, this is a great benefit for the energy transition!
What needs to be done to unleash these market forces and prevent renewables from being deregulated.
However, there are still some hurdles on the way to unleashing this potential: Despite the clear direction of the European legal framework in the Clean Energy Package and despite clear implementation in national law, there are obstacles in practice. Grid operators have no legal certainty in passing on costs incurred by activating storage or consumers for redispatch. The requirements of national law and the specifications of the Federal Network Agency are in some cases diametrically opposed. In this situation, most network operators play it safe and continue to switch off renewables despite significantly higher costs in some cases, instead of using market-based flexibilities. To make matters worse, in view of the prevailing uncertainty, there is also disagreement among grid operators as to the extent to which newly added storage facilities can actually be used to serve the grid. As a result, this often leads to the paradoxical situation that storage facilities tend to be built where there are no bottlenecks, since the grid operator there has no objections to a purely market-driven operation of the storage facilities - we recall the exploitation of price fluctuations on the electricity market described above, which represents a profitable business for battery storage facilities even in the absence of grid bottlenecks.
Unfortunately, this means that the investment incentive to install storage facilities in the right places in the grid has not yet been properly set in Germany. Policymakers and regulators must urgently work with grid operators and the storage industry to find solutions to remove the remaining obstacles. This would be a decisive step toward preparing the power grid for future loads and bringing it a good deal closer to the goal of 80% renewables in 2030.