Power-to-heat and large heat pumps: the electrification of district heating

Why district heating is going electric

District heating has been, for decades, a business of fossil combustion. The bulk of the heat in German networks has come from coal, gas and waste-incineration plants running combined heat and power, with the fuel burned on site to raise the network water to temperature. That fossil generation now has to go, because a heat network cannot be climate-neutral as long as its heat is produced by burning carbon. Decarbonising these networks is the largest and most capital-intensive task of the heat transition, and it is far from solved.

Two electrification technologies carry the change, and they are complementary rather than competing. The large heat pump supplies the renewable base load: it raises ambient heat from rivers, lakes, wastewater, industrial processes or the air to district-heating temperature, and delivers several times the electrical energy it consumes. Power-to-heat through electrode boilers supplies the flexible peak: it turns surplus or very cheap renewable power into heat within minutes, covering demand spikes and absorbing power that would otherwise be curtailed. Together they replace the fossil base and peak load with electricity.

The deeper shift is in how heat generation relates to the power system. A heat network built on heat pumps and electrode boilers becomes a controllable power sink: it can ramp its electricity draw up when renewable power is abundant and cheap and back when it is scarce, so it relieves the power grid instead of burdening it. This is sector coupling in its most practical form, and it is why district heating is increasingly read as part of the electricity flexibility picture, alongside the controllable demand discussed in the analysis of virtual power plants, AI and battery storage.

The scale of the target is what makes the topic urgent. Fraunhofer IEG sees large heat pumps as the most important heat generator of the networks by 2045, supplying about 70 percent of district-heat generation, and it puts the required build-out at about 4 GW of new heat-pump capacity per year. Against an installed base that only crossed 180 MW in mid-2025, that is a step change of two orders of magnitude over two decades, and it has to begin now. The diagram below shows how electricity and ambient heat combine across the two technologies to decarbonise the network.

Large heat pumps: ambient heat at district-heating temperature

A large heat pump does the same thing as the heat pump in a home, only at industrial scale: it takes low-grade heat from the surroundings and lifts it to a temperature the network can use. That makes it the backbone of decarbonised district heating, because it delivers renewable heat continuously and at a multiple of the electricity it consumes, rather than burning a fuel. The art of the technology is in the source and the temperatures it has to bridge.

The heat sources are the starting point. Large heat pumps draw on river and lake water, on wastewater from sewage works, on industrial waste heat from processes that would otherwise vent it, on ambient air, and on near-surface geothermal energy. Each source has a different temperature and availability profile, and the choice of source shapes everything downstream. A warmer, steadier source such as treated wastewater or process waste heat gives a higher and more stable performance than cold winter river water or ambient air.

The technical envelope is wide. Output ranges from about 500 kW to over 50 MW thermal, the coefficient of performance (COP) sits at about 2.7 to over 3, meaning the unit delivers roughly three units of heat for each unit of electricity, and supply temperatures reach up to 130 C and above, which is enough for many existing high-temperature networks. Modern units increasingly use natural refrigerants such as isobutane or ammonia, both to meet the supply temperatures and to avoid synthetic refrigerants. The COP is not a fixed figure: it falls with a colder source and a higher required supply temperature, so the source and the network temperature together decide the economics.

In the merit order of a heat network, the large heat pump takes the role the fossil base-load plant used to hold. It runs as renewable base and mid-load, displacing fossil combined heat and power and gas boilers, while the electrode boiler and storage handle the flexible top. Sizing it correctly against the source and the network temperature is therefore the central design decision: oversize it and it runs at a poor COP at the margin, undersize it and fossil generation stays in the mix longer than it needs to.

Flagship projects: Mannheim, Hamburg, Stuttgart

The technology is no longer a pilot. Several German utilities already run large heat pumps in real district-heating operation, from river water to wastewater, and these reference projects set the scale and the benchmarks for what follows. Mannheim is the clearest example of the trajectory. MVV put the first river heat pump, at 20 MW thermal with a COP of about 2.7 and a supply temperature up to 99 C, into operation in 2023. Its second plant is a different order of magnitude: at 165 MW thermal it is currently the world's largest river heat pump, it uses isobutane as the refrigerant to reach up to 130 C, it goes into construction in 2026 and into operation from winter 2028.

Hamburg shows the wastewater route. Hamburger Energiewerke brings online a 60 MW wastewater heat pump at the Dradenau sewage works from 2026, built from four 15 MW modules, which will supply about 39,000 households and save about 90,000 tonnes of CO2 a year. Treated wastewater is a particularly good source because it stays comparatively warm and steady through the year, which lifts the COP relative to a cold-water or air source. Stuttgart-Muenster shows the waste-heat route: EnBW has run a 24 MW large heat pump since 2024 that uses the waste heat of a waste incinerator to supply about 10,000 households.

The aggregate picture confirms the ramp-up. Installed large-heat-pump capacity in German district heating rose from about 60 MW in 2023 to over 180 MW by mid-2025, and about 70 further projects with over 900 MW of capacity are in planning. The trajectory is steep but still far below the Fraunhofer IEG target of about 4 GW per year, which is exactly why the regulatory acceleration and the funding discussed below matter: the projects exist, but they have to be built much faster.

Power-to-heat: power into heat when power is cheap

Power-to-heat is the simpler of the two technologies and, in system terms, the more striking. An electrode boiler, or a large immersion heater, passes current through water and heats it directly for the district-heating network, at about 99 percent efficiency and controllable within minutes. It does not match the heat pump's efficiency, since it turns one unit of electricity into one unit of heat rather than three, but its value lies elsewhere: it is the fastest large sink for power that the system has too much of.

The case for it is written in the price curve. In 2025 there were 573 hours of negative power prices on the exchange, with a daily low on 11 May 2025 of about minus 250 euro per MWh. In those hours wind and solar generation exceeds demand, and without a sink the surplus has to be curtailed. An electrode boiler turns exactly that surplus into stored heat, so the power-to-heat plant earns its keep precisely when power is cheapest or paid for, which is the inverse of the logic that governs the wider tariff models and the controllable electricity market.

The grid service is the second half of the value. Because the electrode boiler can take up a regional power surplus on command, it can be used for redispatch and balancing energy: when a grid region has more wind than its lines can carry, the boiler absorbs the excess locally and reduces both the curtailment of renewables and the cost of redispatch. That is the same congestion problem addressed from the grid side in the analysis of Redispatch 3.0 and market-based congestion management, and the power-to-heat plant is one of the cleanest answers to it.

The flagship project is Berlin. BEW, together with 50Hertz and Stromnetz Berlin, is building one of Europe's largest power-to-heat plants at 120 MW, made of three 40 MW electrode boilers, to turn surplus wind and solar power into district heat instead of curtailing it. The transmission system operator 50Hertz contributes up to EUR 75 m and in return gains five years of redispatch access to the plant, with commissioning planned by the end of 2028. Vattenfall already operates the Karoline power-to-heat plant in Hamburg on the same principle, feeding the northern German network and easing wind curtailment and redispatch.

The GeoBG: acceleration for heat pumps and heat lines too

The biggest brake on these projects has not been the technology but the time it takes to plan and permit them, and that is what the Geothermal Acceleration Act (Geothermie-Beschleunigungsgesetz, GeoBG) is meant to release. It is not a draft: the Bundestag passed it on 4 December 2025, it came into force on 23 December 2025, and one provision, section 6, takes effect from 22 June 2026. The law is recent enough that many projects now in planning will be the first to run under it.

The decisive point for district heating is its scope. Despite the name, the law is not limited to deep geothermal energy. Its official title names geothermal plants, heat pumps, heat lines and heat storage, and it places the construction and operation of all of them in overriding public interest, serving public health and safety, until climate neutrality is reached in 2045. That status changes how authorities and courts have to weigh these projects against competing concerns, in favour of building them.

For heat lines, the act creates a dedicated accelerated plan-approval and plan-permission procedure, modelled on the one for gas and hydrogen lines under the Energy Industry Act, with shortened steps. For large heat pumps from 500 kW thermal, it removes the suspensive effect of lawsuits, so a challenge no longer halts the project while it is litigated, and it makes the higher administrative court the first instance, which cuts the number of court stages. Both measures shorten the path from decision to operation. The full legal mechanics of the procedure, the deadlines and the individual acceleration levers, are a separate topic in their own right and are taken up here only as an accelerator, not analysed in depth.

Funding and implications for utilities

Acceleration removes time risk, but the capital still has to be found, and that is the role of the Federal Funding for Efficient Heat Networks (Bundesfoerderung effiziente Waermenetze, BEW). It carries about EUR 5 bn through 2030 and is built from modules that follow the lifecycle of a project: from the transformation plan and feasibility study, through systemic and single-measure investment funding, to an operating-cost subsidy for heat pumps and solar thermal that helps over the years when electricity prices weigh on the running cost. A new application portal opens from April 2026. Together with the GeoBG, the funding lowers both the planning time and the project risk for exactly the investments utilities have to make.

For a utility the practical work starts before any procurement. The first step is to map the available heat sources around the network: which river, lake, sewage works, industrial site or air volume can deliver heat, at what temperature and how reliably across the year. The second is to match that source and its temperature to the network's supply temperature, because the COP, and with it the economics, depends on the gap the heat pump has to bridge. The third is to find a site for power-to-heat that has the grid connection and the redispatch potential to make the electrode boiler valuable as a flexibility asset, not just as a peak-load source.

The plant strategy that follows is hybrid by design. The large heat pump carries the base load, the electrode boiler covers the flexible peak and absorbs cheap surplus power, and thermal storage decouples generation from demand so that the heat made when power is cheap can be used when it is needed. This hybrid centre replaces the fossil generation step by step rather than all at once, which is also how it interacts with supply security: as fossil combined heat and power is displaced from the heat side, the questions of firm capacity move to the power system, the subject of the analysis on the Power Plant Security Act and H2-ready plants.

One thing this analysis deliberately leaves to a later treatment is how such a hybrid centre is actually run from day to day. Deciding minute by minute whether to draw on the heat pump, the electrode boiler or storage, against power prices, redispatch signals and the heat demand, is a data-driven operating problem in its own right, and the economic value of the whole investment depends on getting that dispatch right. That digital operation optimisation of hybrid energy centres is a separate topic, an outlook beyond the technology and the regulation set out here.

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