The IRA Includes a Big Push for Heat Pumps, But States Can Do Even More

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The Inflation Reduction Act (IRA) became law one year ago, on August 16, 2022. Its billions in investment for the clean energy transition includes considerable resources to spur heat pump adoption across the country. But how much of an effect will it have? Will the IRA on its own accelerate heat pump adoption enough to help the United States meet its climate goals? And if not, what other policies and regulations might states consider to bridge the gap?

RAP and CLASP are seeking to answer these questions in a paper that will be released this fall. Our research models the IRA’s effect on the uptake of electric heat pumps and concludes that while the IRA is a major step forward, state policies will be needed to propel even greater heat pump adoption to fully bridge the gap. The paper will present several policies and regulatory recommendations to help states build on the IRA to further increase heat pump adoption.

The IRA and Heat Pumps

The IRA contains hundreds of billions of dollars in new spending and tax breaks intended to modernize the U.S. energy system, promote clean energy, reduce health impacts, and increase tax revenues. Most importantly, the IRA provides a framework for U.S. economy-wide GHG emission reduction.

One important aspect of the clean energy provisions within the IRA is heat pump adoption. Heat pumps are the key technology for decarbonizing buildings and will need to be deployed rapidly to realize emission reductions in the buildings sector commensurate with meeting emission reduction goals.

The IRA programs that support the deployment of clean and efficient heat pumps will be important drivers in scaling the adoption of these important technologies in American homes and businesses. Two of the more significant programs to heat pump adoption are the High-Efficiency Electric Home Rebate Act (HEEHRA) and the Energy Efficient Home Improvement Credit (Section 25C) tax credit. HEEHRA provides point-of-sale consumer rebates on appliances including heat pumps, in order to enable low- and moderate-income households across America to electrify their homes. The 25C tax credit provides up to $2,000 in tax credits to lower the cost of a heat pump installation, a savings of up to 30 percent.

The Impact of the IRA on Heat Pump Adoption

Our paper will present an analysis of the impact of the IRA on household adoption of heat pumps. The analysis compares a business-as-usual heat pump adoption scenario with a scenario reflecting incentives from the two key IRA programs, HEEHRA and 25C. It finds that the IRA will prompt more than 2 million households to switch from gas to electric heat pumps by 2032. Considering that 61% of U.S. households used natural gas for at least one energy end use in 2020, this leaves plenty of space for state policies to add to what the IRA is doing.

This modeling adds to the existing literature, which indicates that while the IRA is a major step forward, decarbonization of the building sector will require additional policy initiatives to get to a path toward full building electrification.

Policies for States Looking to Expand Heat Pump Adoption

State and local governments have a range of policies and program options that can help clear barriers to heat pump deployment. These options have been tried and tested and can be ramped up to create a supportive market environment, provide additional funding to support heat pumps, give consumers tools and information they need to make educated choices, and enable more equitable receipt of benefits for citizens. State-level options for promoting the uptake of heat pumps include:

  • Improved public access and participation will ensure that the IRA delivers GHG savings in all communities, especially with communities of color, indigenous communities, low-and moderate-income communities, and other communities that may be underserved by agency programs.
  • A clean heat standard can apply to wholesale fuel providers and promote the adoption of cleaner and more efficient alternatives to fossil heating fuels, for example, heat pumps.
  • Hybrid heat policies can support the practice of adding a heat pump to supplement a building’s existing fossil heating system to both cool and heat a home more efficiently and at lower cost.
  • Energy efficiency programs can be ramped up and focused on supporting heat pumps in buildings whenever existing systems are being replaced.
  • Flexible rate designs with time-varying volumetric charges can promote flexible operation of heat pumps, while reducing costs for consumers and supporting integration of renewable energy.
  • Workforce training and development is essential to upskill existing energy system workers and train new workers on heat pump technologies.
  • Tariff on-bill financing can help manage up-front costs for customers who would otherwise not be able to afford efficient and clean appliances like a heat pump.

The IRA is a great leap toward electrification, decarbonization, and incentivizing the deployment of heat pumps. States and localities can build on the IRA and bridge the remaining decarbonization gap by adopting their own policies and programs that further heat pump adoption.

The UK is sleepwalking into a big problem with its gas network

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To decarbonise the UK, the long term use of gas for heating, including any potential for hydrogen, is limited. Getting off gas is now an obvious climate change and energy security necessity. Both the UK government and its adviser, the Climate Change Committee (CCC), have signaled the need for the gas network to be wound down.

It should be crunch time for the regulation of gas network infrastructure. With government due to make a decision on the future of the gas grid in 2026 and Ofgem now planning for the next price control period (to start in 2026), this is a critical juncture in UK energy network regulation.

But, to all appearances, it’s still business as usual for these heavily regulated parts of the UK energy system, which continue to have capital poured into them. This is exposing UK citizens to significant financial risk while bolstering gas network returns.

The system is risky for consumers

There are large financial liabilities associated with the gas grid, related to stranded assets and decommissioning costs. Yet little thought is being given to them or how they should be managed, apart for some work by Frontier Economics for the CCC seven years ago.

The UK’s gas distribution networks are privately owned and split across four companies. These are regulated by Ofgem to operate the networks and, where they are allowed, to invest in new or replacement assets. Assets in these networks are costed by Ofgem to give something called a ‘RAV’, or regulatory asset value, and networks get a financial return on this. Networks can also profit from their operations. Ofgem assumes a certain amount for running costs and if the networks do better, consumers and networks share the difference. This system hasn’t always worked in the best interests of consumers.

The current regulatory model assumes that gas network assets have long lives; assets are given a 45 year financial lifetime; ie gas network owners recoup the costs of their investments over a 45 year period.

As the customer base shrinks, costs will rise

And herein lies the first problem: If we’re going to move to low carbon heating by 2050 and, as seems to be increasingly clear, the gas network will only play a very small role at that point, there is a significant stranded asset problem. Even with ‘front-end loaded’ depreciation, we are still talking about multiple billions (perhaps £3 or £4 billion) of stranded assets in 2050. And that’s assuming all capital investment stops in 2026, which it won’t; the Iron Mains Risk Reduction Programme (the big yellow plastic pipes you see when roads are dug up) is expected to continue to 2032, so these assets won’t be paid off until 2077.

Compounding this issue is that, over time, the number of consumers attached to the network will decrease rapidly if climate targets are to be met. So gas network charges will increasingly fall on a smaller number of customers. Without mitigation, increasing transportation costs could lead to a gas disconnection network death spiral and major equity impacts, as those without the means to switch, end up trapped.

The second issue is about the decommissioning of the gas grid. For obvious safety reasons, leaving a pressurized network of pipes full of an explosive gas across the entire country would not be sensible. In the UK currently, as was the case for me, if you get rid of gas appliances and have your gas meter removed, eventually the local gas network operator will come and make the supply line safe. This can involve digging, cutting the service pipe and then capping it underground as close to the main as is possible. This comes at a cost, borne by the network, unless (bizarrely) you ask them to come and do it, in which case you pay. This strange process and cost allocation is currently being considered by the government but highlights the need to think about what happens to the gas grid in a much more co-ordinated way.

The government needs a plan to manage the risks

If all 23 million connected homes do eventually remove their gas meter, there is a big question about how such a programme should be funded and what needs to happen in practice. This is a big unknown but, as cost estimates suggest around £8 billion, clearly efforts should be made to understand the practical and financial implications. In any case, decommissioning is an uncosted liability, the costs of which will sit with UK energy consumers.

In a briefing, just published, I consider the options for government and the regulator to attempt to manage these risks. Each has upsides and downsides.

Under option 1, the government could maintain the current regulatory model, and Ofgem could shorten the depreciation timescales to reflect the net zero target, and also collect a levy to fund decommissioning. This would mean higher gas bills and probably very significant equity impacts.

Under option 2, Ofgem could regulate gas network companies to become clean heat providers, mandating a shift towards becoming heat network owners and operators. This would make use of existing skills and relationships but comes with risks around how to regulate such a complex transition, particularly when network companies have been unwilling to shift their business models and have lobbied heavily for continued gas use.

Under option 3, the government takes a much more active approach and, as Denmark has done, renationalises the networks, with the express goal of running them down. Such an approach would enable a more co-ordinated and planned exit from gas, but it would transfer all stranded asset risks and decommissioning costs to the government. Equity impacts could potentially be more actively managed.

All of these options require a significant change from business as usual and there is no obvious frontrunner. But business as usual does not seem able to run-down and decommission regulated infrastructure rapidly in response to major external pressures.

Alongside broader reforms needed for the heating sector, I recommend four government actions, none of which should be particularly controversial, considering what’s at play, and all of which reduce risks for consumers. These are: to improve understanding of what’s needed and the costs; for the Department for Energy Security and Net Zero, Ofgem and others to work together on a plan to allocate the high costs and risks associated with stranded gas assets and decommissioning; to consider whether the Iron Mains Risk Reduction Programme is value for money and intervene if not; and, finally, to ensure heating policy and planning across the country is properly co-ordinated with gas grid decommissioning.

This is a problem laden with consumer risk and significant equity implications. The sooner something is done, the more those risks and costs can be limited and the faster climate action will be.

The original version of this article appeared in Inside Track, the Green Alliance blog. 

Decompression: Policy and regulatory options to manage the gas grid in a decarbonising UK

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For countries with significant proportions of gas in their heating mixes that are looking to decarbonise and reduce exposure to gas imports, there is a major question around how to deal with existing gas distribution infrastructure in an equitable way which supports consumers. Yet this question has received only limited policy focus.

This briefing considers this problem for the United Kingdom, a country which has a well-developed gas distribution network with high coverage (85% of homes) which is both privatized, fully unbundled and split into regions — and which is looking to remove direct fossil fuel use in heating by 2050 at the latest.

The UK energy regulator, Ofgem, is imminently due to embark on a price control process to regulate the gas networks from 2026 onwards and the UK government is also expected to make a decision on the potential of a role for hydrogen in heating in 2026. We hope this briefing can support policy makers and regulators working on these processes.

If decarbonisation of heating by 2050 is successful, there is a high likelihood of stranded UK gas network assets. There will also be some costs associated with the physical disconnection of buildings and decommissioning of the gas grid. Ultimately, consumers bear the responsibility for and risks of these issues. The briefing proposes three options for the British government to manage better these issues on behalf of consumers:

  1. Business-as-usual wind-down with accelerated depreciation and the potential for a decommissioning fund.
  2. Evolutionary regulation to encourage gas networks into clean heating.
  3. Nationalisation with planned wind-down.

In addition to the above, we would encourage greater consideration of the issues of decommissioning, continued capital investment and the role for local area energy planning in gas network decision making. While regulation, governance and ownership vary between countries, many of the technical and regulatory challenges in countries with major gas distribution infrastructure will be similar to the UK.

How to reap the benefits of district heating? Make it local

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The city of Groningen in the Netherlands has long been home to Europe’s largest fossil gas field. As fossil fuel production winds down, city authorities are looking for alternative residential and commercial heat sources. One of the solutions they found is a district heating system using locally available waste and renewable heat.

Clean, efficient and smart district heating, like the system being built in Groningen, can play an important role in decarbonising our buildings, using the huge potential of excess, ambient and renewable heat and providing crucial energy storage and flexibility.

But, matching this supply of clean heat with demand requires a coordinated policy approach and substantial infrastructure investments. The decarbonisation of existing and the development of new district heating networks will need to be aligned with making buildings ready for clean heat.

In countries with extensive fossil gas use, there is the added challenge of simultaneously phasing out gas grids. Moreover, end users will need to have confidence that district heating will be a good choice financially, environmentally, and in regard to service provision.

This is not easy. But, if lawmakers, regulators and industry can get three things right—heat planning, societal trust and regulatory frameworks—we stand a good chance.

Local heat planning

Heat, especially the low-temperature heat that most clean sources provide, needs to be used close to where it is produced to be energy-efficient and prevent high infrastructure costs. Similar to the electricity sector, heat production will be increasingly decentralised, as we switch to clean heat.

Local heat planning is a crucial instrument in matching local demand and supply of heat. This involves mapping locally available clean heat sources and heat demand, assessing area building stock and identifying solutions with the lowest societal cost for each region.

Municipal authorities are well placed to lead this process and bring together the key actors involved such as district heating and building owners, operators and users and potential suppliers of heat. Yet very few European countries require their local governments to engage in strategic heat planning.

The Nordic countries have a long history of heat planning. More recently Germany, the Netherlands and Scotland have introduced obligations for municipalities to do so.

The revised European Union (EU) Energy Efficiency Directive, however, will make heat planning mandatory across the EU for all municipalities with over 45,000 inhabitants. Although this obligation is a great start, it should be expanded to include smaller municipalities and will require careful implementation and monitoring.

Regulatory update

Municipalities cannot do this alone. They will need a supportive regulatory framework.

Firstly, national governments could empower local jurisdictions with the authority to decide which heating solution should be deployed for each area (known as zoning) and set standardised methodologies for decision-making, for instance on how to weigh societal costs and benefits of different solutions, and how to prioritise when each area is switched to clean heat.

Secondly, regulation should find a balance between enabling economically viable business models for district heating while protecting end users. District heating systems are often vertically integrated, with one entity operating both the distribution network and delivering heat to end users.

Moreover, networks are natural monopolies. Once consumers are connected, it is costly for them to switch, and it is not attractive for competitors to set up a rival network. This means relying on competition between providers to drive down prices does not work well in the heat sector.

There are different ways to address this issue, with some countries limiting district heating profits, and others regulating heat and connection prices or ownership models. The challenge is finding a model that ensures district heating can provide affordable heat while ensuring public and/or private investment in the construction of new infrastructure.

Finally, it is key to provide long-term certainty and the assurance that enough end users will connect to the networks. As upfront investments are high and payback times long, a critical mass of heat demand is necessary for networks to become economically viable.

Societal trust

It is important that lawmakers and industry also work on building trust among potential end users. This will be key in areas where district heating is currently underutilised, such as northwestern and southern Europe, because people are usually wary of “new” solutions, even more so when it comes to a significant investment decision such as changing their heating system.

Although, according to a recent EU-wide survey, public perception of district heating varies between countries, people saw a risk of becoming dependent on a single energy supplier when joining a district heating system. Moreover, in several countries, there was an overall negative perception of district heating.

In Denmark and Sweden, countries with the most positive public view of district heating, transparency and provision of information to consumers have shown to be key elements in bolstering end-user trust. It facilitates monitoring of the sector, leading to increased accountability on pricing and performance—a safeguard that regulatory frameworks can foster.

Act quickly

Clean, efficient and smart district heating has huge potential, but governments need to act quickly. Consumers rightfully expect clear direction and clarity on how to heat their homes in the future.

If action is not taken soon, municipalities and consumers will not be in a position to make informed decisions about their clean heat solutions. Heat pump markets are booming, with prices of installation dropping and newer, smaller and more efficient models further increasing their attractiveness. Yet in many, especially urban, areas, district heating will be the most economical choice.

Heating with existing fossil boilers will become increasingly expensive as the expanded EU Emissions Trading System goes into effect in 2027. This date might seem far away but is just around the corner considering the long planning timelines for energy infrastructure.

As the date nears, people will vote with their wallets and switch to individual solutions such as heat pumps in areas that could potentially be served by a district heating network, at lower overall societal cost.

To make the most out of the benefits district heating has to offer, we need to accelerate the development policy and regulations for the deployment of clean district heating.

The original version of this article was published here in Foresight. This is the third part in a district heating series written by Sem Oxenaar. The first and second parts are also available in Foresight.

Business as usual? Heating and cooling in the EU’s updated Renewable Energy Directive

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On 28 June, a committee made up of members of European Parliament finally signed off on a new EU Renewable Energy Directive (RED III), the landmark law that aims to speed up the deployment of renewable energy across the EU. This paves the way for a final plenary vote in September and final rubber stamping from Member States after that. Once the Parliament and Council formally adopt the deal, it will replace 2018’s RED II.

The provisional political agreement reached back in March garnered plenty of media attention – in part because of last-minute political hold-ups to its formal signing off – but also for its increase to the headline target: the EU has now set itself on a binding path to double its share of renewables in final energy consumption by 2030, from 22% in 2020 to 42.5%. This is a large increase in ambition from the previous target of 32%. To achieve it, the share of renewables in heating and cooling, around half of the EU’s final energy consumption, should also reach around 43% by 2030.

However, despite overcoming weeks of political roadblocks to win over the Parliament’s Committee on Industry, Research and Energy on 28 June, the RED III agreement contains important, unresolved issues that hamper its effectiveness for renewable heating and cooling. Member States can fill these gaps with more ambitious efforts, but they must move quickly.

EU heating and cooling: RED struggles to ramp up ambition

RED II aimed to address heating and cooling by setting an indicative sub-target for Member States to gradually increase the use of renewables for purposes such as space heating and cooling, industrial process heat and more. The updated RED III is set to make this sub-target binding. Once it becomes law, each Member State must achieve an increase in its share of renewable heating and cooling: an annual 0.8 percentage point increase from 2021 to 2025 and 1.1 percentage points annually from 2026 to 2030. For example, if a country’s share is 20% in 2023, then it must be 20.8% in 2024.

Unfortunately, RED III’s binding targets do little more than follow this existing, business-as-usual path.

This target falls short of putting Europe on a decarbonisation pathway for heating in line with the bloc’s climate targets, however. RAP’s 2022 publication Metrics Matter explored the math behind the previous sub-target in detail. We found that the share of renewables in heating and cooling has been rising at around 0.6 percentage points per year over the previous decade. With renewables currently contributing 23% to heating and cooling, it puts the EU on track to only reach about 31% by 2030 under the current trajectory.

Unfortunately, RED III’s binding targets do little more than follow this existing, business-as-usual path, as shown in the figure below. Our calculations show that if the EU achieves the bare minimum percentage-point increases outlined in the RED III, it will still only reach a renewable share of 32% in heating and cooling by 2030, just above the status quo trajectory of 31%. In other words, the EU has set itself a target that it can achieve while continuing with business as usual.

Although the picture may look different when broken down by Member State, as the binding targets apply to each country individually, RAP calculations show that an increase of at least 2.0 percentage points annually – starting in 2020 – would be necessary to achieve a level high enough to reach the RED III headline target.

Bar graph showing share of renewable energy in heating and cooling in Europe based on current trajectories and targets, from 17% in 2010 to 23% in 2020 and 31% estimated for 2030

Not all renewable energy technologies are created equal

Another issue with RED III is which renewable energy technologies will be used. Here, a major sticking point is biomass. By and large, over the past decade, the biggest increases of renewables in heating have been observed in countries where biomass constitutes a significant share of heat production, especially in district heating. Not all Member States can follow suit, nor should they, as the potential for biomass use is limited and can be accompanied by sustainability issues. That means a new approach is needed, and electrification of heat – for both individual heating systems and district heating – is widely expected to play a central role.

Yet heating technologies using electricity have previously been disadvantaged in RED II for two main reasons. One, any electricity used for heating (and cooling) did not count towards the heat target in RED II. It simply was not considered in the sector; all renewable electricity statistically was placed in the power sector bucket. Concerning electric heat pumps, only the ambient heat harnessed by the heat pump was classified as “renewable,” whereas the electricity used to drive the process, even if renewables-based, was not. This means that, with electrification technologies unable to fully count towards meeting the EU’s heating target, there was less incentive to deploy them, and more incentive to install alternatives, including combustion technologies for biomass.

In fact, renewable combustion technologies are heavily favoured due to a second key reason: the way the units of renewable heating are counted. The methodology to determine the contribution of each renewable energy technology accounts for the energy harnessed to make the heat (for example, by burning biomass), not the useful heat itself. In other words, it does not reward efficiency.

Member States can ensure that the right incentives are in place to encourage efficient heating systems over inefficient combustion.

Consider an application where you need 100 units of heat. A 50% efficient furnace would need 200 units of biomass to produce this heat. Yet, those 200 units of biomass are counted as “renewable energy consumption.” While in the case of an electric heat pump with an efficiency of 300% (the coefficient of performance is 3), the 100 units of heat could be produced using only 33 units of electricity and 67 units of ambient heat. Previously, RED II only counted the 67 units of ambient heat towards the renewable energy target; the 33 units of electricity – even if it came from renewable sources – did not count. Counterproductively, this punishes heat pumps for being efficient by undervaluing their contribution to the renewable energy target.

Member States have important tools to hand

Fortunately, RED III seems to have addressed the calculation methodology issue. It now considers renewable electricity used for EU heating and cooling as contributing to the target if devices have an efficiency above 100%. This tricky wording avoids crediting inefficient electric resistance heaters with a renewable energy contribution.

What still remains unresolved, however, is the failure to fully value electrification technologies. The least-efficient devices are still credited with producing the most renewable heat. Efficient devices such as heat pumps have received a small boost under RED III, but combustion technologies retain a serious advantage and are likely to be further deployed to help meet EU Member States’ binding renewable heating and cooling targets.

Although it is now too late to adjust the RED III text, Member States can nevertheless ensure that the right incentives are in place at national level to encourage efficient heating systems over inefficient combustion. That means easing permitting, investing in skills and manufacturing, providing targeted support to low-income households and rebalancing taxes and levies from electricity onto fossil fuels.

Lowering flow temperatures is key in the switch to efficient clean heat

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Two important factors are advancing the shift to clean heating in Europe: First, the fossil gas crisis underscored the value of saving energy and the urgent need for affordable heat for all. Second, the race to meet climate goals has inspired many European countries to introduce policies that prioritise clean and renewable heat over fossil-fuel-based heating sources.

The European Union (EU) is still heavily reliant on fossil fuels when it comes to space heating, with three-quarters of the energy used coming from fossil sources. Reducing the flow temperatures of water in heating systems is a key method for saving energy from heating and for integrating a more diverse range of clean resources into the heating mix. As such, this relatively novel approach is a no-regrets option for building owners and occupiers. Lowering the flow temperature can improve the efficiency of heat pumps, solar thermal collectors, condensing boilers and district heating systems.

A critical consideration when lowering flow temperatures is ensuring that buildings can still be heated to the desired temperatures. Changes to two key variables can be considered to decrease flow temperatures: reducing the heat load of the building through building fabric improvements and increasing the heating capacity of the heat distribution system. Understanding this interaction is important for decisions on best-placed investments.

A new report by ifeu and the Regulatory Assistance Project explores approaches and policy measures to ensure buildings are ‘low flow temperature ready.’

How clean is Europe’s district heating?

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District heating needs to speed up decarbonisation to reach climate goals

Over the past year, how we heat our buildings has become a top priority for most citizens, businesses and governments. And rightfully so, as a third of all energy in the European Union (EU) is used for heating and hot water in buildings, 72% of which comes from burning gas and oil.

As people seek to replace coal heating and oil and gas boilers due to the energy price spikes, demand for highly efficient and easily deployable heat pumps has boomed.

Millions of households in the EU, however, rely on district heating systems for their heating and hot water. In 2017 (latest data available), 12% of heat for space heating and hot water in the EU was supplied through such systems — and only one-third is generated from clean sources. Current district heating users cannot make the switch to clean heat by themselves.

To reach Europe’s 2030 climate target, the heating sector needs to rapidly speed up the rate at which it is decarbonising. Many buildings now using fossil fuel boilers will have to be connected to newly developed clean district heating systems while existing district heating systems will need to be modernised and switched to clean heat sources.

Slow progress

Overall, district heat in Europe is largely dependent on burning fossil fuels, waste and biomass. Gas dominates, making up 32% of the heat mix (see chart, below). With a high share of coal and lignite (26%), the sector is relatively greenhouse gas intensive.

The share of renewable heat has been increasing slowly but surely over the past decade — from around 7% in 2000 to 21.5% in 2017 — but it predominantly comes from burning biomass and biofuels (22%) and renewable waste (7%).

These have limited potential to expand and can have sustainability issues. Although their contribution is currently marginal (<3%), the clean sources with the most growth potential are industrial waste heat, geothermal, large heat pumps and solar thermal.


Source: European Commission, 2022a.

Mixed bag

Looking at the regional level gives a more differentiated picture. Many European cities constructed district heating systems as part of their post-World War II redevelopment. In the central and eastern parts of Europe, the sector expanded rapidly early on.

Consequently, many of these systems are now outdated and inefficient compared to current standards. Production plants are old, with more than 70% of coal and oil-based plants still operating beyond their technical lifetime.

Heat losses from distribution are excessive due to high flow temperatures, lack of pipeline insulation and leaks. Combined with a large share of older and less efficient buildings, limited controls and metering for end users, and a high prevalence of energy poverty, these systems face significant modernisation and decarbonisation challenges, while needing to keep heat affordable.

Success stories

In the Nordic countries, mass deployment of district heating came later, following the 1973 oil crisis. As a result, and through ongoing modernisation, those systems have been built according to higher efficiency standards, often with insulated pipelines and combined heat and power production.

Significant steps towards phasing out fossil fuels have been made, using biomass and renewable waste. In Sweden, fossil fuels only make up around 10% of the district heating mix.

The Baltic states have also achieved high shares of renewable heat, making use of the large biomass waste streams from forestry. They do face efficiency challenges in district heating and buildings, however.

The higher investments in both district heat deployment and decarbonisation in the Nordics and Baltics have some relation to the climate, as countries with high heating needs are over-represented among the top-performing countries in these categories.

Finally, there are several EU member states with significant heating needs — such as France, Germany, the Netherlands, Belgium and Hungary — that have invested too little in district heat, far below their cost-effective potential, and face the challenge of quickly expanding district heating.


Source: European Commission, 2022a, and European Commission, 2022b.

The competition

Europe’s district heating systems need to accelerate the switch to low-carbon sources if we are to reach climate goals and give all households access to clean heat. The biggest challenge lies with the older and fossil fuel-intensive systems.

Luckily, there is enormous potential for clean district heating based on renewable heat, ambient heat with large-scale heat pumps and excess heat.

District heating needs to be able to compete economically with a booming and innovative heat pump market, however. In addition, especially in countries where district heating is currently less developed, trust must be built among end-users often weary of novel solutions.

Moreover, regulations have to be updated to support viable business models and protect end-users, and buildings will have to be made ready to be heated comfortably and efficiently with lower temperature clean heat sources.

This is no easy feat, but with the right policy and regulatory support, clean, efficient and smart district heating can play an important role in decarbonising our buildings.


A version of this article originally appeared on Foresight Climate & Energy.

Photo credit: Vera Simon Thomas