As climate policy scenarios show, the electrification of heat supply will play a key role in the transition of district heating systems over the next two to three decades. At the same time, the transition of the electricity system from fully adaptable to fluctuating, renewable electricity generation requires greater demand-side flexibility. District heating based on power-to-heat generation, combined with thermal storage, can provide this flexibility: through flexible procurement in wholesale markets and by supplying ancillary services, particularly frequency control.

By Shervin Balali, Expert Renewable Heat, Dr. Jana Bosse, Senior Expert for Renewable Heat, Dr. Rita Ehrig, Team Leader for Renewable Heat, and Dr. Tim Mennel, Lead Expert for Market Design, German Energy Agency (dena)

Published in Hot Cool, edition no. 2/2026 | ISSN 0904 9681 |

The analysis presented in this article is based on a literature review of publicly available studies and reports, as well as eleven structured interviews with Danish and German industry experts. Participants included professionals from district heating companies, transmission system operators, and researchers.

While Denmark and Germany both strive to electrify their heating network supply, they are currently at different stages of development. Denmark already meets a notable share of its heat demand through power-to-heat technologies, harnessing their flexibility to support the electricity system. In contrast, German district heating providers currently use very little power-to-heat appliances, with plans to expand their use in the future. In that respect, Germany resembles other European nations seeking to decarbonise their district heating systems.

For district heating operators, electrification is not only a path to decarbonization but also offers new revenue opportunities through participation in the electricity market by providing flexibility. District heating can provide flexibility, for example, through system-friendly geographical relocation of heat generation and the provision of ancillary services. At the same time, participation in wholesale and ancillary service markets can improve the techno-economic performance of heat-generation assets and strengthen the business case for electrified heating technologies overall.

The supply of ancillary services is one of the challenges for an electricity system with a high share of renewable energy, and the provision of flexibility through wholesale markets is another.

The electricity grid has no storage capacity. Supply and demand must thus be constantly balanced, or, in technical terms, the frequency of the European interconnected alternating current grids must be equal to, or close to, 50 hertz. To ensure network stability, network operators procure so-called ancillary services from participants in the electricity markets [1].

The procurement of ancillary services is organised along grid zones rather than bidding zones. Western Denmark and Germany are both part of the Continental European System Area (CESA), one of the largest synchronous electrical grids in the world [1]. Most of the regulations and requirements are therefore identical, although there are some differences in national implementation. Overall, the following ancillary services are available for frequency control (also called balancing services) in this control area: frequency control reserve (FCR), automatic frequency restoration reserve (aFRR), and manual frequency restoration reserve (mFRR). The services differ in terms of the activation timeline; see Figure 1.

Figure 1: Balancing services in CESA (own illustration based on Nextkraftwerke, 2025 [2])

In the past, thermal electricity plants provided the bulk of ancillary services; in particular, gas turbines with their high reactivity are technically suitable for frequency control and other ancillary services. Moreover, pumped hydro storage plants contribute to the supply of ancillary services, in particular frequency control. When the expansion of renewable generation began in the 2000s, some observers feared that the fluctuations in wind and solar generation would necessitate vast frequency-control capacity.

Today, it is clear that the warnings were exaggerated. The introduction of intraday markets alleviated the negative effects of fluctuations on the scheduling of generation assets. However, the phase-out of thermal generation at a more advanced stage of the electricity system’s transition creates a need for new suppliers of ancillary services, particularly in systems without (or with only small shares of) hydropower. Some ancillary services can indeed be provided by renewable assets themselves, many others by batteries and by demand response technologies.

It must be emphasised that the use of flexible assets in the electricity system does not end here. Flexible demand (as well as storage) can and is marketed in the spot market. Here, it helps accommodate fluctuating electricity feed-in, allowing for a match of demand and volatile supply via arbitrage. In terms of volume, the spot market is, of course, much more important than the frequency control market: the financial trading volume in the German day-ahead market is around 30 times higher than that of the balancing market.

The provision of ancillary services demands prequalification and different technical requirements.

In Germany, the list of prequalified capacity for frequency control services shows a clear picture: pumped hydro storage leads by a wide margin across FCR, aFRR, and mFRR. Battery storage comes next for FCR, while natural gas plants rank second for aFRR and mFRR. However, this snapshot no longer reflects actual market behaviour. Today, batteries deliver around 95% of FCR.

There has been a sharp rise in new battery storage, mainly due to price advantages linked to temporary exemptions from grid fees. A look at Denmark tells a different story, with prequalified FCR capacity being largely dominated by electric boilers and batteries. Regarding aFRR and mFRR, again, electric boilers play a major role for both up- and down-regulation, followed by wind turbines and conventional plants. Figure 2 summarises the prequalified assets for FCR in Germany and (Western) Denmark.

After many discussions, the EU finally reached an agreement on 3 December 2025 to phase out imports of Russian gas by the end of 2027.

By Morten Stobbe, CEO International, Ingeniør Huse A/S and DBDH Board Member, and Morten Jordt Duedahl, Business Development Manager, DBDH

Published in Hot Cool, edition no. 2/2026 | ISSN 0904 9681 |

We believe that the future of district heating can only be built on flexibility – not as an optional add-on, but as its very foundation. In our view, anything else leads to structurally fragile systems and higher long-term costs.

Electricity-based large heat pumps, electrical boilers, geothermal energy, surplus heat, biogas, biomass boilers, waste-to-energy, and biomass CHP – each has its strengths and limitations, and each delivers value under different conditions. A district heating system that can move seamlessly between them does not have to be complicated. We argue that being adaptive and agile is the best proof for resilient future operation and solid long-term economics.

If the ambition is low heat costs for end users (in our opinion, there is no other option), real-time price signals must be available and allowed to do their job. When electricity prices are low, heat pumps and electric boilers should run. Properly designed district heating systems do not compete with the electricity system – they actively support it by providing flexibility, balancing, and demand response. Quietly. Reliably. Predictably.

In this sense, district heating is not merely a consumer of electricity. It is an active and dependable partner in a power system increasingly dominated by volatile renewable electricity generation.

Security of supply is the foundation on which everything else rests – price stability, public trust erodes, and political support. Systems built around multiple heat sources are inherently more robust. They mitigate risk, reduce dependency on single fuels or markets, and increase resilience in times of crisis.
Flexibility is not a luxury. It is insurance.

Overcapacity is not inefficiency – It is strength.

Multiple heat sources are often perceived as unnecessary complexity. We take a different view. Relying on a single dominant heat source is not simplification – it is exposure. Diversity in heat production is a prerequisite for resilience, not a deviation from efficiency.

This is where the discussion becomes uncomfortable, particularly in systems shaped by short-term efficiency metrics. If the objective is to optimise only for the next budget cycle, underinvestment is almost inevitable.

However, if the objective is the lowest possible heat price over the system’s lifetime, the logic changes. Then it makes sense to invest ahead of need, to build flexibility early, and to accept what looks like unnecessary redundancy on paper. What appears excessive today proves essential tomorrow. This, in turn, calls for good planning and modelling skills across the sectors, systems, and technologies.

This is also where ownership matters – more than we often admit. Only district heating companies with a clear legal mandate to deliver the lowest possible prices, rather than short-term returns, can fully embrace long-term system optimisation. Democratic, consumer-owned, or publicly anchored district heating companies are no less commercial-minded. However, they have longer investment perspectives. This makes them more rational from a system perspective. They can invest when it is cheap and invest in extra capacity that delivers lower operational costs and continuously secure lower prices from the heat sources in operation. This is clearly about politics. But it should only be about aligning governance with system logic.

Storage: not a heat source – yet the most important one

With storage, heat sources cooperate.

Thermal storage deserves special attention in this discussion. Storage does not produce heat. And yet, in many systems, it is operated and treated as if it were the most valuable heat source of all. Storage provides flexibility and gives value to waste heat. It decouples production from demand. It allows for the cheapest energy to be produced and captured when possible – even at negative prices when balancing services are delivered to the electricity grid. Without storage, heat sources compete. With storage, they cooperate.

Storage turns volatile inputs into stable outputs.

That statement deserves attention. Electricity prices fluctuate dramatically. Renewable generation varies. Waste heat availability is often irregular. Each on its own, these inputs are difficult to plan around. DH storage absorbs that volatility and releases heat as a predictable, controllable output. From the heat network’s and the customer’s perspectives, instability disappears, and prices are lower.

Storage may be visible infrastructure, but it generally carries a high level of public acceptance, as the battery function is an enabler of low heat prices. It does not dominate headlines. But it quietly enables everything else to perform better. When investments are ranked by system impact, heat storage should be very high on the list.

Flexibility is the key – Just do it!

The real question facing the district heating sector is not whether flexibility is needed. That debate is already settled. The real question is whether we are willing to prioritise investments that may look excessive today but prove decisive over time. Whether we are prepared to view periodic overcapacity as a strength rather than a flaw. And whether we design systems, markets, and ownership structures that allow district heating to think long-term.

We expect that most Hot|Cool readers share these views. However, we believe the discussion around flexibility, overcapacity, and storage has been overly cautious for too long. District heating is too important to avoid taking clear positions.

With a new closed-loop single-well geothermal solution benefiting from the oil and gas industry, geothermal heat becomes accessible everywhere. The geological requirements are minimal, and the issues with conventional doublet-hydrothermal solutions are mitigated.

By Kim Gunn Maver, Camille Hanna, Mads Sylvest Eegholm, and Nikolaj Holmer Nissen, Green Therma

Published in Hot Cool, edition no. 2/2026 | ISSN 0904 9681 |

The new solution almost eliminates heat loss from the returning fluid to the surface and will thereby overcome the currently perceived limitations of single-well coaxial solutions. Furthermore, it increases the heat-harvesting area by adding a long horizontal section, as is common in oil and gas wells.

The solution can play a significant role in the European energy transition and deliver heat directly to the growing district heating grid without the use of heat pumps. As a result, district heating can be largely decoupled from the electricity grid, with a Coefficient Of Performance (COP) of 30-50 and a very limited surface footprint.

Green Therma and its partners have received an €11.5 million grant from the Danish Energy Technology Development and Demonstration Programme (EUDP). The grant will support the full-scale demonstration project, including a 7 km well to be drilled in late 2026. The well will supply geothermal heat directly to Aalborg Forsyning’s district heating customers under a 30-year heat-offtake agreement. The project supports the wider goal of scaling multi-well closed-loop solutions in the global energy mix.

Hydrothermal well solutions

Conventional geothermal systems are based on a doublet design, where one well produces formation water and another well injects/returns cooled formation water. The system is highly dependent on the thickness of the geological formation and the formation parameters, such as porosity, permeability, and geochemistry, to ensure hydraulic connectivity between the wells to maintain water production.

Produced water can cause corrosion, scaling, clogging, and significant maintenance issues in surface installations, the injection well, and the reservoir around the injection wellbore. Hydraulic fracking may be required to improve injectivity and formation connectivity, with the risk of polluting groundwater aquifers, having a detrimental impact on the geological formation, inducing seismicity, and potentially damaging surface infrastructure.

Because these risks can only be partially mitigated by gathering geophysical and geological data for well planning, the financial viability of a project is highly variable and unpredictable.

Closed-loop horizontal geothermal well design

To mitigate issues with a doublet hydrothermal solution, a patented vacuum-insulated inner pipe circulates a working fluid in a closed-loop well. The working fluid is heated by the surrounding geological formations along a long horizontal section (Figure 1).

The working fluid, similar to the fluid in district heating pipes, flows downward between the well casing and an outer pipe, absorbing heat from the geological formations along the way, especially in the horizontal section. Once heated, the working fluid returns to the surface through a vacuumized pipe-in-pipe assembly, which consists of an inner and an outer pipe working similarly to a thermos flask.

Figure 1: Closed-loop horizontal geothermal well solution.

The continuous and controlled vacuum in the pipe-in-pipe provides thermal insulation, minimizing heat loss (Figure 2). As a result, the temperature of the fluid returning to the surface is reduced to only a few percent. Without a vacuum to insulate the circulating fluid, significant heat loss occurs.

The closed-loop solution is flexible in its heat provision. This is beneficial in cases where heat demand varies seasonally. Flexibility is achieved by either adjusting the flow rate or stopping fluid flow for a period. This allows the subsurface to reheat during under-utilized periods.

In some cases, the flow of the working fluid in the well can sustain itself by the thermosiphon effect due to the heated fluid in the inner pipe being less dense than the cold water in the outer pipe. However, fluid circulation at various flow rates requires a small circulation pump.

Figure 2: Vacuumized pipe-in-pipe solution.

Benefits of a closed-loop well solution

There are several benefits of the closed-loop solution in general, and when compared to the conventional doublet hydrothermal solution.

The solution is largely independent of geology, meaning wells can be drilled in most locations to depths where subsurface temperatures are high enough to deliver heat without heat pumps. That also means that there is no exploration risk – a well will always produce heat.

As the general electricity requirement is only for a 45 kW circulation pump, the solution has a COP of between 30 and 50, depending on the thermal output of the well, minimizing the burden on the electrical grid.

With a very high COP, this solution has minimal CO2 emissions, and the heat pump’s electricity demand could easily be met by a green source.

In a closed-loop system, no fluids circulate within the geological layers, leaving the geology undisturbed. No downhole equipment is required; the circulation pump and surface equipment are based at surface level, gathered in an easily accessible 20-foot container. The operating cost is therefore limited to maintenance. The 20-foot topside facility can be placed below a parking lot or field, requiring only a 50 m by 50 m area around the well. The landscape footprint is therefore minimal. In addition, the initial water requirement is minimal.

With the right design, there will be no tear, wear, and corrosion, which is why the solution should work for more than 50 years.

The road to geothermal everywhere

To further develop the closed-loop solution, the technology is currently being advanced through ongoing demonstration projects.

Testing in Norway

In late 2024, the vacuumized pipe-in-pipe solution was installed at the Ullrigg test site in Stavanger, Norway, and 525 m of pipe was tested. The solution was run to the planned depth for testing the equipment design, measurements, and procedures. The insulation effect and the pipe-in-pipe design were successfully tested for further development.

Installation in a suspended geothermal well north of Berlin

A full installation began in the second half of 2025, with the first heat produced in mid 2026 at Groß Schönebeck, 50 km north of Berlin, Germany.

The Groß Schönebeck site serves to investigate the sustainable provision of geothermal energy from two deep wells completed as an Enhanced Geothermal System (EGS) and is managed by GFZ Helmholtz-Zentrum für Geoforschung in Potsdam.

The GrSk 4/05 well was drilled in 2006 to extract thermal water and to form a doublet system of hydraulically connected boreholes, with a measured temperature of 145°C at 4.4 km. However, high flow rates could not be sustained, and the well is currently suspended.

In late summer 2025, the well’s dimensions and structural integrity were tested and confirmed to be suitable for recompletion. The lowest part of the well, with the perforated section used initially to flow water, will be isolated to create a closed-loop space before installing the closed-loop well completion.

The vacuumized pipe-in-pipe system, consisting of a 3.5-inch inner pipe and a 4.5-inch outer pipe, will be installed to maintain a continuous vacuum from the surface to a depth of 3.2 km. The geothermal performance of the well, specifically the transfer of heat from the geological formations, will be tested to assess the effects of varying flow rates. The average modelled output is 0.4 MW.

The overall performance of the formation’s heat transfer and the vacuumized pipe-in-pipe solution will be evaluated over a one-year period. The geothermal performance test of the solution will further qualify the completion tubing design and structural modelling for circulating varying fluid temperatures in the well.

The Aalborg well

In a collaboration between Aalborg Forsyning and Green Therma — and project partners also including Aarhus University, Aalborg University, Danish and Greenland Geological Survey, and Energy Cluster Denmark — a geothermal demonstration plant will be built in Storvorde. Green Therma will operate the facility and deliver heat for the next 30 years through a heat offtake agreement with Aalborg Forsyning (Figure 3). The project is supported by the Danish Energy Technology Development and Demonstration Programme (EUDP) with 11.5 mill Euro.

In late 2026, the geothermal well with a slanted section will be drilled, and the vacuumized pipe-in-pipe solution will be installed. The well will deliver geothermal heat directly without heat pumps to the city’s district heating network starting in 2027 (Figure 4).

Figure 3: Storvorde well location

The Storvorde location was chosen for its favourable underground geological conditions and proximity to the existing district heating network. These two factors are crucial for the plant to be established. When the plant is completed, it does not take up much space on the surface.

Prior to drilling the well, a 2-dimensional seismic survey of the subsurface will be conducted by trucks driving along roads in the area around Storvorde, emitting a pressure wave into the ground and recording the response. The seismic acquisition results in a better understanding of the local geology, enabling optimization of the final well design.

The total well length is 7 km: 4–5 km vertically, followed by a 2–3 km horizontal section. The vacuumized pipe-in-pipe solution, consisting of a 4.0-inch inner pipe and a 5.5-inch outer pipe, will be installed to maintain a continuous vacuum from the surface to 7 km.

With a geothermal temperature increase of roughly 30°C per km, a virgin temperature of 120–150°C is predicted, with a long-term minimum of 80°C at the surface for more than 50 years, while the return temperature from the district heating grid after heat exchange will be around 40°C. The only energy demand is a 45 kW for a circulation pump for <2 MW well.

Figure 4: Schematic subsurface model.

Becoming competitive through technology transfer from the oil and gas industry

Previously, the economics of coaxial closed-loop geothermal solutions has been questioned because they cannot produce sufficient geothermal heat at a competitive price. This issue is addressed through reduced heat loss from the vacuumized pipe-in-pipe solution, the long lateral well section increasing the heat uptake area, and industrialization of the geothermal drilling process.

A long horizontal section to harvest heat is a best practice and an improved well design, especially from the USA onshore unconventional oil and gas industry. The designs have demonstrated the ability to drive the major production increase in oil and gas production since 2010, and horizontal wells have become the predominant method when drilling for oil and gas in the USA, with more than 75% of all newly drilled wells having a horizontal section.

In a 2024 International Energy Agency report, it was estimated that 80% of the investment required in a geothermal project involves capacity and skills that are common in the oil and gas industry. Furthermore, it was estimated that with the engagement from policymakers and the oil and gas industry, the costs for next-generation geothermal wells could decrease by up to 80% by 2035.

What is next: A multi-well geothermal project

While the operations in Aalborg involve a single well, the plan for future projects is to take a “multi-well” approach across global sites, drilling a sequence of 5–10 wells from a single surface location, each with horizontal sections extending in different directions (Figure 5). This approach will reduce costs per well by minimizing rig mobilization expenses and leveraging drilling efficiency through repetition.

Figure 5: Example of a 5-well closed-loop geothermal well design.

For further information, please contact: Kim Gunn Maver, at [email protected]

Commercial investors are unwilling to make the necessary investments to scale up district heating in Europe. The solution is democratic ownership of district heating utilities.

By Magnus Skovrind Pedersen, CEO of Think Tank Brundtland, and Lasse Skou Lindstad, analyst at Think Tank Brundtland.

Published in Hot Cool, edition no. 2/2026 | ISSN 0904 9681 |

The coming investment wave

Europe is entering the largest heat infrastructure expansion in modern history.
District heating will play a central role in the transition to renewable energy, energy independence, and a more flexible energy system. Most European countries are expected to expand their networks significantly in the coming decades.

How should Europe organize and finance this scale-up?

Commercial district heating investors who demand adequate returns are unwilling to make the necessary investments. This creates a structural financing gap between the investments we need and those that yield a high enough return to satisfy private investors. As a result, we instead need to promote democratic ownership structures, in the form of municipal and consumer-owned utilities, to deliver the necessary investments. The ability of democratically owned utilities to deliver the necessary investments is supported by evidence from the electricity sector, where publicly owned utilities invest more in renewable energy than their private counterparts.

From technical potential to political economy

Infrastructure transitions rarely fail because of engineering constraints. They stall because institutions are misaligned with investment needs.

A research team led by Daniel Møller Sneum recently examined barriers to the rollout of district heating [1]. The conclusion was clear: The most difficult and decisive barriers are economic and political. Not technical.

This finding is consistent with Brundtland’s [2] broader analytical work on energy infrastructure. When transitions require patient capital and governance of natural monopoly networks, ownership becomes central. Markets alone rarely deliver optimal outcomes without institutions that reduce risk and ensure legitimacy.

Commercial investors cannot deliver decarbonized heat at scale

When it comes to assessing risk in the district heating sector, it is essential to distinguish between new and existing systems.

Existing systems benefit from established customer bases and stable operations. Risks are lower and more predictable.

New systems face uncertainty regarding customer uptake, regulatory stability, construction costs, and local capabilities. These uncertainties translate into financial risk.

In capital markets, higher risk directly translates into a higher required return to compensate. Preliminary evidence from research led by Daniel Møller Sneum shows an average required rate of return for commercial district heating investors of around 11%. [3]

In comparison, Heat Roadmap Europe 5 (HRE5) [4] , which outlines a cost-effective strategy to decarbonize heating in Europe, uses a real discount rate of 3% a year to evaluate investments. A discount rate is used to translate future costs and benefits into today’s value. It reflects that money today is worth more than money in the future. The 3% is a real rate (excluding inflation). With inflation of around 2%, this corresponds to a nominal rate of roughly 5%.

But since commercial district heating investors need a 11% return per year, many of the investments that Heat Roadmap Europe points to as necessary at a 5% rate will not be feasible for a commercial investor. This creates a structural financing gap between what society needs and what generates a high return.

From Brundtland’s perspective, this gap is not accidental. It reflects a mismatch between private risk assessment and public system value. District heating provides system benefits beyond individual project cash flows, including flexibility, energy security, strategic autonomy, and emission reductions. Yet these benefits are not fully captured in market pricing. While economists often argue that you can integrate all of these into the market price with the right taxes and subsidies, implementing them can be politically and technically difficult and may not be sufficient in time.

The solution is a different type of ownership that can value the true benefits of district heating. In other words, this requires consumer- and publicly owned district heating that can account for broader societal benefits when making investment decisions.

Therefore, if we want to achieve strategic energy autonomy and a green heating sector in Europe, we need democratic ownership.

Heat Roadmap Europe 5 requires democratic ownership and public credit institutions

While commercial district heating investors will be unwilling to invest in projects with medium or low returns, democratically owned district heating companies are not limited by the same need to maximize their short-term returns.

Interest rates, discount rates, and required rate of return

Figure 1. Source: Think Tank Brundtland based on data from KommuneKredit [5], Danish District Heating Association [6], Heat Roadmap Europe 5, and preliminary results from Møller Sneum et al. [7]

As an example, a democratically owned Danish district heating company can get a loan of around 3.6% per year for a 30-year loan through the public credit institution called KommuneKredit. KommuneKredit borrows through sovereign bonds issued by the Danish central bank. Here, the Danish state can issue a 30-year bond with an interest rate of around 3%.

On top of that, the municipality that facilitates the KommuneKredit loan guarantees the loan and on average demands a yearly guarantee commission of around 0.6%. The combination of democratic ownership and the help of a public credit institution means that the district heating company can borrow at 3,6%. If the goal of an investment by a democratic district heating company is just to “break even”, then the investments in Heat Roadmap Europe 5 discounted at a rate of 5% become feasible.

Democratic ownership increases energy investments

The ability of democratic ownership to increase green investments is confirmed by a growing literature. One study by Steffen et al. 2022 looked at energy utilities across Europe and found that public utilities had a significantly higher rate of investments going towards renewables. This study was based on power utilities, but some of their investments overlap with some district heating as well, such as biomass and geothermal energy.

Share of investments going to renewables in EU-28

Figure 2. Source: Think Tank Brundtland, based on Steffen et al. 2022 [8]

Likewise, research from the OECD has found that a higher level of public ownership among electric utilities is associated with significantly higher investment in renewables. A 10-percentage-point higher share of public ownership in the energy sector was associated with a 31% increase in investment in renewable energy. In comparison, introducing a typical state aid scheme for renewables, a feed-in tariff, was associated with a 10% increase in renewable investment.

Change in renewable investment

Figure 3. Source: Think Tank Brundtland based on Prag et al. 2018 [9]

These results cannot necessarily be translated 1:1 to the district heating sector, but they point to the pivotal role of democratic ownership in accelerating and scaling the green transition.

Democratic ownership is the necessary catalyst

Europe does not lack the necessary technology to expand district heating. It lacks the right institutional framework. Commercial investors who demand double-digit returns leave a structural gap between societal need and private profitability. Democratic ownership, on the other hand, has lower capital costs and required rates of return, enabling patient investment in the rollout of district heating. This is also supported by evidence from the power sector, where publicly owned utilities and companies invest more in renewables. If Europe wants rapid decarbonization, energy security, and strategic autonomy, democratic ownership is essential.

It is not just large district heating companies that are focusing on the need for a green transition. MPEC Ostróda – a smaller district heating company with an annual heat sale of 300 TJ, located approximately 150 km south/east of Gdansk in Poland – started this journey back in 2017. Previously, production was 100% coal-based, but in 2017, it was partially replaced by two gas engines, which could help secure income from electricity sales to the grid. The transformation has begun, and the company is soon to reach its goal: no coal. And since 2024, the district heating price has been reduced with 18%.

By Wojciech Zalewski, CEO MPEC Ostróda, Lars Gullev, CEO Gullev DH Advisory, and Mathias Vestergaard Steenstrup, Project Manager – DH Specialist, Artelia

Published in Hot Cool, edition no. 2/2026 | ISSN 0904 9681 |

What’s the secret behind this development?

The initial stages

In autumn 2023, in connection with work for the Danish Embassy in Warsaw, with a focus on supporting the green transition of district heating (DH) companies in Gliwice and Gdynia, the district heating company MPEC Ostróda was visited. A DH company with committed management that clearly saw the need for a green transition of heat production. Not only to be green, but primarily to ensure that customers’ DH price remained competitive with alternative heating methods. Rising coal costs, including CO2 quota costs, would threat-en a future competitive DH price.

An application to the Danish Energy Agency (DEA) for support in preparing a Development Plan for MPEC Ostroda and continued close cooperation with PEC Gliwice and the Gliwice municipality was submitted in autumn 2023, approved by DEA just before Christmas 2023, and preparation of the Development Plan started in early 2024.

The project aimed to plan the green transition for a sustainable and efficient DH system. MPEC Ostróda also aimed to maintain a low, stable heat price for its consumers and a high level of security of supply, while, as a frontrunner, making the transition from a fossil-fuel-based to a sustainable, efficient DH production.

Signing of the MoU between MPEC Ostróda and DBDH during His Majesty the King of Denmark’s visit to Poland in January 2024. From left to right: Ole Toft, former Danish ambassador in Poland, Wojciech Zalewski, CEO MPEC Ostróda, Lars Aagaard, Danish Minister of Energy & Climate, Pia Zimmermann, Export Manager, DBDH, and His Majesty King Frederik X.

Development from 2017-2024

Changes in broader environmental policies and the Russian invasion of Ukraine in February 2022 have had a significant impact, completely changing the approach to heating in Ostróda.

The years 2022–2024 marked a turning point. Prices of coal, electricity, and natural gas surged dramatically, with costs climbing almost daily. Heating prices for residents reached unprecedented levels, setting a new record for the company. The company’s aim became to survive in the market.

Following these events, the company decided to invest quickly in new heating production to reduce heating costs for residents in Ostróda. Thus, the company and the city of Ostróda in 2024 invested in a 4.6 MW biomass boiler – the first sustainable heat production source in the history of the company, not subject to CO2 taxes.

The company changed its natural gas and electricity contracting policies for its combined heat and power (CHP) operations, partnering with the Finnish company FORTUM, thus start-ing a new chapter in its operations. The new cooperation principles and stock market con-tracting brought the first results by the end of 2023, as the company presented a significant profit from sales of electricity, which helped cover the loss from coal-based production – main-ly CO2-related expenses.

But it didn’t stop there. Since October 2023, MPEC Ostróda has been establishing a 10 MW natural gas-fired boiler. The tender closed in March 2024, the contract was signed in April 2024, and the boiler went into operation at the beginning of 2025 (figure 1).

Figure 1: Sankey diagram of the energy mix – Simulation 2025.

In addition to significant investments, the development has required support from consumers and, not least, from political institutions. These potential barriers have been identified, allowing them to be addressed to achieve a sustainable and efficient DH supply in Ostróda.

MPEC Ostróda has started addressing these barriers by releasing a short video about the DH company and explaining that its investments, together with changes in fuel prices, have led to an 18% decrease in the heat price since 2024.

The shares of coal, natural gas to CHP, natural gas to boiler, and biomass in 2025 were 15%, 24%, 26%, and 35%, respectively (Figure 2).

Distribution of heat sources in 2025

Figure 2: 2025 heat production – natural gas for CHP, biomass, natural gas for boiler, and coal.

In accordance with the EED, the current energy mix will be insufficient and not fulfill the requirements by January 2027 (see text box below).

The Energy Efficiency Directive of the EU

The objectives of MPEC Ostróda – as mentioned in the text box – are highly related to the revised Energy Efficiency Directive (EED) of the EU. The EED is a directive of the EU that aims to improve energy efficiency in all member states. Introduced in 2012, the directive has undergone several revisions, with the most recent update in 2023, which integrated it into the Fit for 55 package and the European Green Deal – key strategic and legislative frameworks for reducing CO₂ emissions.

Under the EED, efficient heat supply systems must meet the criteria mentioned in the text box.

Basis for a development plan

To set up a development plan [MD8.1][la8.2]for MPEC Ostróda, it was necessary to perform a detailed techno-economic analysis. Implementation of new green production capacity and new technologies requires a thorough understanding of the varied production and heat de-mand, as well as the costs of production. Changes in heat demand and production capacity were analysed using an annual simulation model.

The model was built and simulated in EnergyPRO – a leading software for detailed modeling and simulation of energy systems. The software offers tools for users to conduct feasibility studies, financial analysis, energy production and distribution optimisation, and evaluate op-erational scenarios.

In the software, a wide range of technologies for integrating and analysing various systems can be selected, including large-scale heat pumps, electric boilers, heat storage, geothermal energy, and renewable energy sources such as wind and solar power.

By comparing the model and simulation results with the actual energy mix and operating costs, a reference operating cost was determined.

By running several simulations with iterating capacities and combinations, the most economi-cally and practically feasible solution for a sustainable and efficient DH supply of MPEC Os-tróda was identified for 2030. The following mix also considers fuel diversity and efficiency, as was pointed out in the strategy (figure 3).

Figure 3: Sankey diagram of the energy mix of the 2030 model and simulation.

Roadmap 2030

By addressing all criteria and conditions, a roadmap (fig. 4) for MPEC Ostróda to meet the EED criteria and to have a more sustainable and efficient supply of DH, was made.

Figure 4 Roadmap 2030 of investments needed to obtain a sustainable and efficient DH supply.

Spin-off from the development plan

Through the development of a strategy aiming to implement a sustainable and efficient DH supply, criteria for procedures and investments have been found. These criteria will ensure a future DH system that is economically feasible and technically sufficient.

The techno-economic evaluation has shown that a mix of solar thermal collectors, heat pumps, and the existing biomass boiler and CHP unit, together with thermal energy storage capacity, is an optimal solution.

Figure 5: Simulated shares of production of MPEC Ostróda in 2030.

Based on the requirements of the EED and projected share of RES in the electricity sector, MPEC Ostróda’s simulated share of RES from heat production is 66%, fulfilling both the re-quirements of 2028 and 2035.

Also, the share of RES and high-efficiency CHP combined amounts to 85%, fulfilling the re-quirements of 2035. However, this requires a slight increase in the efficiency of the two CHP units at MPEC Ostróda. An overview of the contributions from each production unit is shown in Fig. 5.

Based on the production share shown above (Fig. 4), the total CO2 emissions amount to 8,400 t/year. The reduction in CO2 emissions corresponds to 59%.

Therefore, the aim of CO2 emissions (see text box) by MPEX Ostróda is not met. However, most CO2 emissions come from CHP, which is considered efficient and contributes to a greener electricity supply in Poland.

Correct investments, visionary management – that’s the cocktail for success

All in all, the green transformation of MPEC Ostróda is a fine example of how visionary management can translate vision into action, while the investments made lay the foundation for a still-competitive district heating price. Without the green transformation, MPEC Ostróda would not have been able to deliver a competitive product to its customers.

The experience from MPEC Ostroda can be used in many district heating companies in Poland and other countries. So, use your personal network to exchange experiences. This way, the green transition can be made more affordable for customers, society, and the environment.