Rheinhafen steam power plant Karlsruhe

No decision has yet been made to invest in the Karlsruhe power plant site because no invitation to tender has yet been issued. However, EnBW is examining the option of investing in new gas-fired generation plants at its existing power plant sites, not least because continued use of these sites offers many advantages and would be particularly cost-efficient. It can generally be said that EnBW can and will only invest if the underlying political conditions permit the profitable operation of these power plants. In principle, Karlsruhe is a very good location. Assuming a suitable funding concept were in place within the framework of the Electricity Supply Security and Capacity Act (“Strom-Versorgungssicherheits- und Kapazitätengesetz” or StromVKG), EnBW would press ahead with corresponding projects in order to be able to participate in the planned power plant tendering procedures. The dimensions and technology of a new power plant are then determined by the district heating requirements of the potential customers, among other things.

Dispatchable power generation capacity is needed in Baden-Württemberg in order to reliably meet the demand for electricity at all times. Renewable energy sources cannot continuously meet this demand, and coal power plants should no longer be used for this purpose in the future due to their carbon emissions. Even though battery storage systems are dispatchable, they are only available for short periods of time (no more than a few hours) when needed. For this reason, gas power plants that can later be converted to use hydrogen as an energy source are set to close the existing gap.

In our view, the EnBW site in Karlsruhe is well suited to the construction of such a gas power plant in Baden-Württemberg. The planned combined cycle gas turbine plant in Karlsruhe is primarily designed to deliver a flexible electricity supply when there is insufficient wind and solar energy or grid stability needs to be maintained. Battery storage systems can only do this for a short period of time. Without the plant, coal power plants that produce significantly higher carbon emissions would have to provide the necessary cover in the longer term.

To date, Stadtwerke Karlsruhe has been purchasing district heating from the RDK 8 coal power plant. As soon as market operation of RDK 8 ceases and it is placed in the grid reserve, regulatory requirements mean that it will no longer be possible to extract heat for district heating. It could then be replaced by the new RDK 9 gas power plant. Drawing off heat from the new RDK 9 plant for district heating is technically possible and would also be factored into the plans – provided that Stadtwerke Karlsruhe had an interest in the available district heating. Like RDK 8, the power plant’s primary focus would then be on meeting electricity demand, known as a power-driven plant. This means that it could only provide district heating at times when electricity production is needed and the power plant is therefore in operation. For this reason, a combined cycle gas turbine plant such as RDK 9 can and will only be one of several building blocks used to generate district heating for the city of Karlsruhe. In short, RDK 9 can take on the role previously performed by RDK 8 in generating district heating, but will supply district heating with significantly lower carbon emissions and also provide the option of carbon-free district heating by converting the power plant to run on hydrogen at a later date.

No, since RDK 9 will be a power-driven plant, it will only be able to supply district heating when it is in operation for the purpose of meeting electricity demand in any case. A combination of several optional district heating sources will therefore always be needed, which will then be used depending on availability and cost-effectiveness. District heating from a gas power plant, for example, nicely complements heat generated by large-scale heat pumps. That’s because both types of plants operate in diametrical opposition to one another and the heat pumps can produce cheaply when electricity prices are low and a power-driven gas power plant is not operating.

The term “energy transition” describes the path from electricity generation based on carbon emissions to carbon-free electricity generation. In this sense, a multistage decarbonization process involving one element of energy generation infrastructure also represents part of the energy transition. Even when operated using natural gas, a modern combined cycle gas turbine plant emits only half as much carbon per kilowatt-hour of electricity generated as a modern coal power plant, thus representing a first step toward decarbonizing electricity generation in a comparatively swift and cost-effective manner.

In terms of the energy transition and reducing gases that have an impact on the climate, it is not the installed power plant capacity that matters, but the amount of electricity generated in each power plant. The level of electricity demand in the market is driven by the consumers. For electricity generation and effective climate change mitigation, the question of which carbon emissions can be used to meet demand then becomes relevant. If building a new and highly efficient gas power plant (which can generate one kilowatt-hour of electricity with carbon emissions of around 370 g) results in a coal power plant previously operating in the intermediate range (with carbon emissions of over 800 g per kilowatt-hour of electricity generated) being transferred to the grid reserve, where, based on experience, it will only run for a small number of hours per year, this will really help to reduce carbon emissions, making it a key component of the energy transition. Investing in new dispatchable power plant capacity is also the basic requirement for gradually being able to completely decommission older coal power plants that have been transferred to the grid reserve on account of their system relevance.

In our opinion, the commissioning of a large-scale combined cycle gas turbine plant should even make it possible to decommission reserve power plant capacities for good, although this is unlikely to initially affect RDK 8, which is very efficient for a coal power plant, but an older block such as RDK 7, which produces a higher level of carbon emissions.

Natural gas (or methane) and hydrogen (H₂) have very different properties, which means that it will always be necessary to convert a power plant before making the switch from natural gas to hydrogen. The key advantage of an H₂-ready power plant, however, is the fact that this conversion is technically possible in the first place, having already been taken into account in the basic design of the power plant components. As a result, the cost of subsequent conversions will only run to a small, single-digit percentage of the original investment cost. It is important that power plants like the one planned for RDK 9 can be converted with relatively little complexity as soon as hydrogen is available in sufficient quantities and at competitive prices. We are ultimately aiming to use 100 percent hydrogen. If natural gas is still needed for technical reasons following the switch to hydrogen – to start up the turbines, for example – this will only produce a small amount of carbon emissions due to the short start-up time of the turbines.

That is difficult to predict at this point in time because it depends on many factors. The main questions here relate to when a sufficiently powerful connection to the planned upstream hydrogen core network will be possible. Then the hydrogen must be available on the market in sufficient quantities and must ultimately also be able to compete with other fuels in terms of cost, especially natural gas. The last point could also be achieved through regulatory measures, for example, such as two separate hydrogen tendering processes, as set out in the cabinet resolution relating to the Electricity Supply Security and Capacity Act. On the other hand, a binding switch to hydrogen or climate-neutral operation of the plants is also required from 2045 as part of the regulatory framework. Based on current estimates, EnBW expects a changeover date sometime in the second half of the 2030s.

EnBW’s clear aim is to use green hydrogen. During the ramp-up phase in particular, however, it may well be that green hydrogen alone would not be available in sufficient quantities or would still be too expensive due to the existing cost structure. Among other things, this would delay the switch to hydrogen. Blue hydrogen, which is produced in a process known as steam methane reforming, is much more cost-effective. The CO₂ that is produced in this process is captured before being permanently stored. Blue hydrogen is therefore a sensible bridging option, not least because the actual product is essentially identical to green hydrogen, which means that it can gradually be substituted by green hydrogen at a later date without having to make further changes to the power plant technology or supply pipelines. We therefore consider it legitimate to look for cheaper ways to achieve the desired decarbonization of dispatchable electricity generation, even if this may involve intermediate steps – via so-called blue hydrogen, for example. For this reason, EnBW is advocating approval of the use of blue hydrogen within the regulatory framework, but that in itself is not the same as EnBW solely wanting to use blue hydrogen in the long term.

Absolutely not! A project like RDK 9 needs to meet all requirements under planning law – by demonstrating compatibility with the development plan, for example – and requires approval pursuant to the Federal Immission Control Act. The project will also go through all these steps independently of the resolution passed by Karlsruhe Municipal Council. This explicitly includes the usual public consultation process prescribed in such cases. From EnBW’s perspective, however, the resolution represents a valuable starting point for quickly being able to take the next steps as mentioned above. The resolution should therefore be seen as an important first milestone.