Inside The Netherlands’ Bold Energy Future: Lessons From TenneT & Beyond – CleanTechnica

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At the end of my engagement with TenneT, the Netherlands’ transmission system operator, who I assisted with 2050 scenario planning for their target grid, I had the opportunity to sit down with a couple of members of the workshops to discuss our findings. What follows is a lightly edited transcript of the first half of our conversation.

I’d like to add a special thanks to Johnny Nijenhuis of Nijenhuis Trucking Solutions in the Netherlands, who volunteered his podcast studio, mics, and sound editing for this.

Michael Barnard [MB]: Hi, welcome back to Redefining Energy–Tech. I’m your host, Michael Barnard. I’ve got a special edition from the Netherlands today. My guests are Paul Martin, a returning friend of the podcast series who needs no introduction, and Emiel van Druten, an employee of TenneT and the reason Paul and I are here in the Netherlands. Welcome, Paul and Emiel.

Emiel van Druten [EVD]: Hello. Hello. 

[MB]: So why don’t we start with you, Paul. Give the ten-second version of yourself since you’re already well known. 

Paul Martin [PM]: Sure. I’m a chemical engineer, known as a skeptic of hydrogen and synthetic molecules. I’ve worked in chemical technology development my entire career. 

[MB]: And Emiel, you’re new here and relatively new to podcasting. I think this is only your second time, so at least you’re not a complete beginner. Tell us a bit about yourself and how you ended up at TenneT, and in a position to ask Paul and me, as Canadians, to fly thousands of kilometers to come and help you. 

[EVD]: Yes. What I do at TenneT is develop future energy system scenarios with my colleagues. As a TSO [transmission system operator], we use those to look ahead to 2030 and 2050 and ask, what will the energy system look like? Then we run grid calculations to see where the bottlenecks will be and where we need to invest in the grid. That’s my job, and we don’t do it alone. We work together with the other network operators in the Netherlands, the gas TSO, and the regional DSOs [distribution system operator]. Every two years we create new scenarios, and we use those to guide our investment plan, which looks 15 years into the future. 

Currently, we’re looking ahead to 2040 with a target grid, and even further to 2050, to outline a blueprint for the future grid we may need to build. At the very least, we can begin preparing for it. In this context, I invited you both as experts to review our scenarios and ask: do they make sense? Do they make economic sense? We want to prepare for a highly electrified scenario. Is our version of “most electrified” realistic, or is your best guess even higher? That’s why we spent last week together in a four-day, quite intense but enjoyable workshop. We’ll talk more about that today. But first, let me explain how I ended up in this position.

I started at TU Delft, where I did a bachelor’s in mechanical engineering, then shifted to civil engineering and completed a master’s in hydraulic engineering. You might wonder: how does a “mechanical water guy” end up working on energy systems at a TSO? That path started with my master’s thesis. I did an internship at an engineering and consulting firm, and I asked if I could work on something at the boundary of water and energy. They said, well, since the Netherlands is mostly below sea level, rainwater has to be pumped out through pumping stations. Many of those stations are at the end of life and due for renovation. So, my thesis project became designing a good renovation strategy for one of these stations.

I did a case study on a site with three one-megawatt pumps. At the time, it ran on gas and diesel engines, but it was being electrified. That became my thesis focus. We actually revisited that very pumping station with you today. That experience introduced me to energy. I realized these stations could operate when electricity prices were low and when wind was abundant, which drew me into the subject. The company where I did my thesis asked if I wanted to work in energy transition because they thought I had a passion for it. I said yes.

I worked there for seven years at the consultancy firm Witteveen+Bos, doing projects on pumping stations and offshore wind. For example, I worked on the wind farm we drove past, calculating what would happen if a turbine blade broke off and how that would affect dike safety. 

[MB]: It was a very Dutch conversation, because the question wasn’t whether a wind turbine blade might hit a person or a cow, but rather: what if it hits the dike? What happens to the dike? 

[EVD]: I was also calculating what would happen if a blade hit one of the high-voltage power lines. The probability I came up with was once in a couple of million years, which was above the threshold of once in a billion years. So I had to contact the TSO, TenneT—where I now work—and ask if they were willing to accept that risk.

I did that kind of work for seven years, across all sorts of projects. I worked on the built environment, helping municipalities develop strategies to get off natural gas and electrify households. I worked on projects for ministries, across different sectors. Over time, I realized I was always optimizing specific client problems, but I wanted to step back and optimize the whole system from a higher level. That pushed me to look for new opportunities.

I also started a part-time PhD alongside my work. I did that for four years, but I discovered it’s very hard to make real progress part-time. I have one paper currently in review on integrating wind, solar, and batteries behind a single grid connection, but when I had a child last year, I realized I was effectively juggling three jobs. That was just too much. I decided to set aside the PhD and later also switched jobs. Now I’m at TenneT, working on scenario development. It’s a great role, because I get to look at all sectors and explore where integration opportunities exist. 

[MB]: TenneT is the company that manages transmission for both the Netherlands and parts of Germany, though in separate systems. Paul and I were here just for the Netherlands portion. It was a fascinating process. And Paul, you were nerding out as much as I was today, because Emiel organized a closing day trip for us. It was incredible—we saw 200 megawatts of wind, 100 megawatts of solar, and in the future there will be another large block of batteries added. 

[PM]: A whole gigawatt hour of batteries in one field. It’s very impressive. 

[MB]: From where we were standing, we could see a gigawatt of generation all in one place. It was multiple companies operating in the same area. The most impressive part was standing at the base of a wind turbine, inside the turbine, looking out at solar panels—and realizing it was all below sea level. 

[EVD]: 5 meters. 

[MB]: So Paul, what was the most interesting takeaway for you from today? 

[PM]: I was beaming, smiling from ear to ear, because it’s so clearly the future. We were looking at what the future of world energy will look like, and imagining that it took eight or nine years to put together. The scale of it is impressive. The local people are engaged, involved, and significant part-owners of the project. Of course, I enjoyed the technical details too, but it was really the sense that we were looking straight at the future. It was very impressive. 

[MB]: Having dealt with a lot of the social side of wind energy in the past, and with both Paul and me having strong ties to Ontario—me being an Ontario boy and still considering Toronto one of my home cities, and Paul living in Ontario and having a farm—we know how different the social acceptance is here. They’ve managed the social aspect of wind energy much better. Yes, they’re running into problems now with new wind projects facing blockages, but the farmers own a big share of this gigawatt of wind and solar. Even with restrictions and setbacks, they’re benefiting directly.

When we were talking about the piles being driven in—50 by 50 centimeter angled piles—the hammering must have been heard for miles around. But for the farmers closest by, what they were really hearing was the sound of money. 

[PM]: Nobody was feeling bad or claiming their health was negatively affected by this kind of project. It’s just another crop coming out of the same field. What’s not to like? 

[MB]: And randomly, this is the first time I’ve ever been inside a wind turbine. 

[PM]: Me too. 

[MB]: I was surprised. Emiel, had you been inside a wind turbine that scale before? 

[EVD]: No, not at this scale. I’m also a member of a citizen development collective called Windville, and I’ve been inside one of their turbines. But that was quite small compared to this one here. This one was seven and a half megawatts. I went inside, and there were multiple containers with the transformers. You could stack three shipping containers side by side, two rows high, and it would all fit inside. 

[MB]: The base was 14.5 meters across. It was a concrete mast, shipped in segments and assembled on site, standing 130 meters high. Seven and a half megawatts from a single turbine. It was stunning—the biggest I’ve seen. 

[EVD]: On land. 

[MB]: Yeah, the entire row was of the largest wind turbines operating on land. So thank you, Emiel, for organizing that. 

[PM]: What impressed me most was that a single turbine could power seven and a half of the polder dike discharge pumps we saw at the pumping station.

[EVD]: Yes, but to be clear—we weren’t just anywhere in the Netherlands. We were in a place that used to be the bottom of the sea. This part of the Zuiderzee, the southern sea, was once open water. After a major flood, the Dutch decided to take measures. They built the Afsluitdijk at the northern end of the Netherlands, tens of kilometers long, to close off the sea. It became an inland lake, the IJsselmeer, fed by the river IJssel. What was once saltwater turned into freshwater.

After that, they asked: what next? The answer was to build an entirely new province on the bottom of the lake by constructing a ring dike. With the dike in place and pumping stations installed, they drained the water. The pumping station we visited today was one completed during World War II. Once the land was drained, it was swampy at first, then dried out, and farmers moved in to establish productive agriculture on the fertile soil.

Today, that same reclaimed land is home to some of the best examples of farmer-led renewable projects, with communities developing large wind farms in the Flevopolder and the Noordoostpolder, where we visited. 

[MB]: The pumping station for the dikes was fascinating too. There’s a 5-and-a-half-meter difference in water level. It uses three 1.2 megawatt pumps, and we were lucky enough to be there when one of them started up. 

[EVD]: It was nice because the operator, Albert, told us that since this year they’ve had hourly energy prices. He looked at the market that morning and scheduled the pumping to start at 11 o’clock. He said they’ll automate the process next year, but for now he chooses the pumping hours each morning. I thought, that’s exactly what I advised nine years ago in my thesis—it’s good to see they’re finally doing it. 

[MB]: They’ve already saved €100,000 with the non-automated process, so once it’s fully optimized, the impact will be fascinating. But this is typical of the Netherlands: they take on big infrastructure projects, look to the future, make bold moves—and then they invited Paul and me to help with one of those bold moves.

To characterize it—and Paul and Emiel can correct me—there’s a national energy scenario process that produces four different scenarios. Some assume high electrification, some low. They used the PESTLE methodology, which looks at politics, economics, and other factors, and built extremes into each scenario to make sure all angles were covered.

But the result was that the high electrification scenario—the one most relevant to TenneT as the transmission operator, the one that implied the greatest transmission buildout and the toughest case for their workload—still had a lot of irrational assumptions baked into it. 

[EVD]: Yes, exactly—because of the method. If you have an uncertainty with a 5% chance of one outcome and a 95% chance of another, the method still requires you to include both in a scenario. That works for explorative scenarios, but for the target grid we want a single picture of 2050 and then work backward. From that, we ask: what does this mean for our system? When do we need to start specific projects, and what can we begin preparing now? For that, you want a likely scenario, not one built around outcomes you think are very unlikely.

That’s one of the reasons we asked you to join us for the workshop. We wanted you to take this scenario and provide an economic sensitivity check—an economic reality check, really. We also wanted to know if our “highest electrification” scenario was in line with your best guess, or if your expectations were higher. Industry is especially important in this context. We do get complaints, especially about the highly electrified scenarios, because they assume a very large industrial base. The Netherlands does have a disproportionately big industry for such a small country: five refineries, a large chemical sector, fertilizer production—all of it made possible because of cheap Groningen gas.

But that advantage is gone now, since we closed the Groningen field due to earthquakes. We do have the North Sea for offshore wind, but does that mean we can keep all our existing industry and remain competitive? That was the real question we wanted you to address. In this scenario, where everything from raw material to final product is kept in the Netherlands and hydrogen is used heavily in all processes, is that economic? Or is there another, more realistic path? That was my question to you.

[MB]: For me, one of the surprising things about the Netherlands was realizing that in many ways it serves as the refinery for Europe. Crude oil comes into the big ports, flows into the five major refineries, and then about 70% of the output transits the country and goes on into Europe. 

[EVD]: We even export finished products like lubricants back to America—the same place the oil originally came from. 

[MB]: That’s obviously an industry in transition. Paul, what surprised you about the Netherlands’ industry—the things that stood out as big or unexpected, the ones that made you think, “Huh, that’s odd”? 

[PM]: Well, I don’t think I was surprised by industries being there. I was surprised by the fact that they were still in the scenarios that were evaluating for the reasons that Emiel has mentioned and that we needed to kind of surgically remove them in order to make sure that we ended up with a, a view of the future that is internally consistent, you know. You know, to give you an example, about between 15 and 25% of every barrel of oil gets turned into something that’s not going to be burned at its end of life. Well, you can’t clearly maintain an industry that produces the other 75 to 85% of the barrel and sells it to somebody else to burn in a future where you’re not burning anything that’s just inconsistent. 

And so as a consequence we had to go in and say, well yeah, you have maintaining this industry in here. What you really need to be considering is maintaining the chemicals and materials portion, the smaller fraction of that and having a world dominant industry position in that area that’s going to persist in a decarbonized future whereas the fuel burning portion of it isn’t. So yeah, anyway, that’s the sort of thing that were brought in to provide advice about. And I guess the other thing to mention is it wasn’t just Michael and myself. You know, there were other experts that were brought in. 

In particular Dr. Helene de Coninck. I’d been reading her group’s papers for some time and not realizing it was her. But, but yeah, she was part of the process. And we also had Reinier Grimbergen. 

[MB]: Emiel, could you give us a quick potted bio of Helene? She’s accomplished an enormous amount in her career. 

[EVD]: Oh yes. Helene was actually my co-supervisor for my PhD at the Technical University in Eindhoven, where she’s a professor focused on systems in transition. She’s also an IPCC author—she was one of the lead authors on the 1.5-degree report. She serves on the government’s scientific council and is involved in many expert groups on the energy transition. She’s really a key expert in the Netherlands.

[MB]: Yes, and I really respected her moral compass, because she held our feet to the fire on negative emissions—not just getting to zero. 

[EVD]: Then there was Reinier Grimbergen. We invited him on the day we focused on industry and transport fuels. Paul is clearly an industry expert, but Dutch industry is so particular in its structure that we thought it would be valuable to also bring in a Dutch industry expert who knows the landscape and the existing considerations. Reinier is a private consultant with a company called Science to Innovate, where he helps firms test new ideas and innovations. He’s also part of a startup developing a new process to bring to the Netherlands: methanol to olefins. Olefins are key in chemistry, and his process can work with imported methanol or methanol made from plastic waste and residual waste streams.

That’s why we brought him in. In the scenario process we run with Netbeheer Nederland, we hold stakeholder sessions and invite existing industries and their representatives. They often say, “We don’t like these changes, we’d prefer to see the refinery sector remain larger.” Sometimes that leads to adjustments in the scenarios. We also create storylines and go to the really big companies, asking, “In this world, what would you do?” They respond with how they’d decarbonize, and we incorporate that into the scenarios. But new industries and emerging technologies are underrepresented in that process. That’s why we invited Reinier, and he made a great contribution. 

[MB]: Another segment that surprised me with its sheer scale was the greenhouse industry. In the original scenario, the plan was to shut down the 2.5 gigawatts of combined heat and power engines that provide heat, electricity, and carbon dioxide to the greenhouses—about 5 million tons of CO2 a year to enhance growing conditions. As we worked through this, one of the clear points Paul and I agreed on was to keep all of that generation as capacity. Then you can power it with stable sources and use it flexibly—just as Paul does with the generator on his farm. 

[PM]: The important thing about a backup power device is that it meets two criteria: it has to be reliable, and it has to be cheap. The capital cost must be low. It doesn’t need to be efficient, and it doesn’t necessarily need to have low emissions, because by definition it won’t be used very often. But it does need to be inexpensive to keep around. And what’s cheaper than equipment that already exists, is headed for the scrap heap, and only needs maintenance? Why wouldn’t you keep that capacity?

Another interesting point was the Netherlands’ potential to generate methane from biogenic sources—through anaerobic digestion of different feedstocks, and from properly processing agricultural waste that would otherwise emit methane into the atmosphere and worsen global warming. The potential there is quite significant. Essentially, it’s about redeploying a resource that has been used in the wrong way and turning it into something useful—as stored fuel. 

[EVD]: In recent years, the line of thinking in the Netherlands—and in most of the scenarios we developed in earlier rounds—was that everybody wanted green methane. 

[PM]: They all want it because it’s familiar, but not necessarily because of the price. We want to burn it—but we want to burn it the right way. 

[MB]: We also want it as an industrial feedstock, and we want to burn it occasionally. 

[EVD]: Yes, it had been planned for the built environment. The Netherlands is quite focused on hybrid heat pumps—installing a heat pump but keeping a gas backup boiler for when it gets too cold. If that backup runs on green gas, then it’s carbon neutral. That’s a major part of the strategy. 

[MB]: We put a kibosh on that one pretty quickly. 

[EVD]: Another example is the transport sector, where LNG is used as a fuel, with the idea of switching to green LNG. But you both said, no—just electrify that. Plus, LNG engines have the problem of methane slip, and methane is still a greenhouse gas. 

[PM]: There are many places in the world that aren’t interested in taking that half step to methane, whether it’s biogenic or not. They don’t want to deal with the greenhouse gas implications from leakage, venting, and engine slip. So why tie yourself to that path when there are other beneficial uses that don’t suffer from those same downsides? 

[EVD]: What we found is that if you remove all the green methane use from the built environment and transport, you free up quite a bit that can be redirected to industry. We’ll get to that later. But it can also serve as a backup fuel for really cold periods—the typical Dunkelflaute, lasting a few days to two weeks in winter, when it’s cold, cloudy, and windless. In those times, wind and solar aren’t generating, and batteries are drained after half a day.

So it made the most sense to keep the existing methane plants and the combined heat and power plants in the greenhouses and run them during those hours. We had enough green gas to cover that. The current picture in the Netherlands, however, assumes all of that will be hydrogen power plants, either converted or newly built. 

[MB]: And anyone who’s listened to Paul or me will know we shut down the idea of hydrogen for energy pretty quickly. 

[PM]: That got a fork in its rear end pretty fast. 

[MB]: Yes, there’s a clear thread here. Right now, our biomass waste streams are massive sources of anthropogenic methane, which is a major global warming problem. The process we’re pointing to is regionalized biodigesters that capture and produce biomethane, preventing the methane emissions Paul mentioned. What’s left are nutrients like potassium and phosphorus, which can be returned to the soil. 

[PM]: Back to the fields—and in many cases a good portion of the nitrogen too, depending on the biomass source. You recover much of the nutritive value for fertilizer use that way. And on top of that, you’re getting energy. What’s not to like? 

[MB]: Paul and I have been bullish for years on this: if you already have a strategic natural gas reserve and infrastructure that burns natural gas, then put biomethane into that reserve. That becomes your Dunkelflaute store—because the system already exists. 

[PM]: As I said before, backup power devices run very infrequently by definition. You don’t want to spend much capital on them—you want to keep costs as low as possible. So store a year’s worth of biomethane in the existing infrastructure. Support those facilities, maybe even nationalize some of the assets if necessary, since they’ll be used so rarely that they become more like strategic reserves. They exist for societal resilience against emergencies, which industry often struggles to fund on its own. Or perhaps it could be supported through some kind of capacity market. 

[EVD]: Yes, there are different levels to this. At TenneT, my group is also responsible for the adequacy outlook, where we look ahead and ask whether we’ll be tight on generating capacity during those cold weeks. We signal to the ministry if we expect shortfalls in the coming years—toward 2030 and 2035. The ministry is now considering whether action is needed, and whether capacity mechanisms or capacity markets could ensure that assets which are no longer economically viable still remain available as backup. 

[MB]: And the same thing applies to Dunkelflaute. Paul and I kept having this recurring experience over the past week—looking at each other and saying, wow, are we ever envious as Canadians. 

[PM]: For sure. The Netherlands is so far ahead in many ways. In Canada, we have tremendous natural advantages, but for one reason or another we don’t seem very eager to take advantage of them. In the Netherlands, it’s the opposite. The country is physically small and constrained in ways Canada isn’t, yet they’re much further ahead on decarbonization overall—even though they started from a tougher position, being literally underwater. 

[MB]: On that note, one area where they’re far ahead of almost the entire world is seasonal thermal energy storage. Emiel, didn’t you design something in that space once? 

[EVD]: Yes, that was the kind of project we worked on at the engineering company—developing aquifer thermal energy storage. 

[MB]: Why don’t you describe that? People outside the Netherlands often don’t know what it is. 

[EVD]: If you go into the subsurface at a hundred or a couple hundred meters, you find sand layers. When those sand layers are sandwiched between impermeable clay layers, that’s ideal, because you can pump water in and out without losing it. You drill two wells: one for extraction and one for injection. You pull up water from the extraction well—it’s not hot, but around 20 degrees—and in winter you can use a heat pump to upgrade it to about 40 degrees to warm a building. The cooled water is then reinjected into the other well, creating a cold store. In summer, you reverse the system: you bring up the cold water to cool buildings, which is especially valuable for commercial buildings with large cooling needs.

The heat from summer is stored underground and brought back up in winter. It’s essentially a seasonal balancing mechanism. Greenhouses use this too, since they have surplus heat in summer from sunlight. By storing it underground, they can use it in winter. The Netherlands already has thousands of these aquifer thermal storage systems in operation, and we’re continuing to scale them up. The greenhouse sector in particular is adopting them widely. In the past, greenhouses relied on combined heat and power plants for baseload heat. Now those plants can be retained as backup for when it’s very cold and electricity prices are high.

The beauty of the system is that if you switch on the CHP in those conditions, it can supply electricity for the heat pump, which is the baseload source, so you don’t have to buy expensive grid power. Any additional waste heat from the CHP also goes straight into the greenhouse. It’s a really elegant example of system integration. 

[MB]: Yes, and the Netherlands has a couple of significant advantages with aquifer thermal energy storage. One is that there are plenty of sand layers, since the country sits on a mix of sandstone and shale. 

[EVD]: It’s actually just loose sand, not stone. 

[MB]: Good point. The second advantage is that the Netherlands has deep expertise in directional drilling from its oil and gas industry. They know how to steer drills horizontally underground, and not every country has that capability in its corporate base. That means if an aquifer is offset a kilometer or two to the side, they can still reach it. But then the Delta T becomes important. Paul, do you want to dive into the nerdy details of Delta T and how this thermal storage works? 

[PM]: In the original scenario we reviewed, there were a lot of hybrid heat pumps. To give an example, in a place like Alberta in Canada, winters are so cold that the coefficient of performance—the ratio of heat a pump delivers to the electricity it consumes—drops significantly. It gets to the point where you might as well use resistance heating.

The Netherlands, though, has a much more moderate climate. So we were surprised to see hybrid heat pumps there—systems that actually burn fuel to provide heat for the pump during the coldest days. Given the climate, it seemed unnecessary.

This ties back to the Delta T Michael mentioned—the difference between the cold source you’re drawing heat from and the hot space you’re pumping it into. That temperature lift is the work the system has to do, and it drives the efficiency. In the Netherlands, the Delta T is small, and with aquifer seasonal storage providing surprisingly efficient heat retention from summer to winter, the required lift is very modest. That means coefficients of performance are exceptionally good, which makes the entire system much more sensible. 

[EVD]: Yes, but it only works if you have district heating. It’s a large-scale project—you don’t build it for 100 households. You need several hundred homes plus some commercial buildings to make it viable. District heating is great because it allows system integration with multiple sources: you can have a baseload source, a power-to-heat boiler that kicks in when electricity prices are zero or negative, and a backup option. That’s not feasible at the single-household level, because maintaining three systems for one home doesn’t make economic sense.

That ties to what you pointed out about hybrid heat pumps. Having two systems in individual homes, and keeping the gas distribution network alive just so households can use a few hundred cubic meters of gas a year, simply doesn’t work. In the end, the fixed costs of the gas connection make each cubic meter extremely expensive. That creates a strong incentive to eliminate those last few hundred cubic meters, even if it means relying on electric heating. It’s better to design a proper heat pump from the start and go all-electric, instead of adding a hybrid system and then later trying to phase out the gas side. That was our conclusion.

Another odd focus we saw in the Netherlands is in the government cost-effectiveness models. They put too much emphasis on fabric efficiency—insulation. They assume you need to retrofit buildings to near new-build standards before installing an all-electric heat pump. 

[MB]: To qualify for a grant for an all-electric heat pump, they added a requirement that you first meet high insulation standards—a failure common in many governance and regulatory systems. 

[EVD]: I’m not sure if it’s a subsidy requirement, but the model assumes that you can only switch to all-electric or low-temperature district heating if your home has at least a label B energy rating. If you’re at label D or just moderately insulated, the model suggests it won’t work. But in practice, with good design and by optimizing the heat exchange system—like adding ventilators to radiators—you can make it work.

My own home runs on an all-electric heat pump with only radiators, no floor heating. I added ventilators, and I achieve a COP of three and a half to four. My house is fairly well insulated, but there are plenty of other examples, with metering data, showing you can get solid performance from an all-electric system even in older houses. 

[MB]: Oh yes. And as I understand it, the model assumed it would cost around €100,000 in fabric upgrades to bring the average house up to top-grade standards.

[EVD]: Yes, at least something like €30,000. That’s comparing apples and pears. If you force all-electric systems to carry the burden of very expensive, non–cost-optimal insulation, while hybrid heat pumps only need minimal upgrades, the comparison is skewed. With just modest, cost-effective insulation, you can make all-electric work. That’s why I want the model changed to allow label D homes to go all-electric.

They did run a sensitivity analysis, though, assuming all houses were upgraded to near new-build, label B standard. When they re-ran the cost optimization under that assumption, almost no hybrids were deployed, and there was very little district heating. If buildings are so well insulated that they need very few gigajoules per square meter, the high cost of district heating pipes doesn’t pencil out. The result was 80–85% all-electric individual heat pumps. That’s what we chose to include in the scenario: eliminate the last 10% of hybrids, move to roughly 80% all-electric individual solutions, and around 15% district heating. It could be optimal to raise district heating to 20%, but socially it’s difficult.

In the Netherlands, every household has to sign up for district heating, and you need at least 90% participation to make the business case work. That requires local ambassadors to convince neighbors, but the people most likely to be ambassadors are the early adopters of all-electric heat pumps—who have already solved their own problem. So, in practice, only the neighborhoods officially designated by municipalities as future district heating zones, with clear communication to residents, have a strong chance of success. Elsewhere, it’s a very hard sell to get enough people to sign up. 

[MB]: One of the things I’ve observed is that the Netherlands is a victim of its own success in some areas. With district heating, for example, I’ve pointed to regulating gas distribution utilities to become heat-as-a-service providers. Companies like Vattenfall and Ennatuurlijk were already doing that. But they were gouging customers on the cost per BTU of heat, which upset a lot of people. Now municipalities are pulling that responsibility back and saying, “We don’t want you involved—we’ll do it ourselves.” 

[EVD]: The short version is this: heating is regulated, and the rule is that district heating service shouldn’t cost more than what a household would have paid with a gas boiler—the “not more expensive than before” principle. But in the calculation, they include an expensive maintenance contract and a costly boiler. As a result, the tariff ends up higher than what many people actually paid before. Add in the high fixed fees, and people are understandably annoyed. That’s created a lot of negative sentiment.

They’ve been working on revising the law for collective heat—what we call district heating—for several years now, but it’s gone back and forth. Municipalities are increasingly saying they should own and operate the systems themselves, and the process is moving in that direction. But the delays are piling up. In the meantime, heat pumps keep getting installed, and the very people who might have been ambassadors for district heating are instead becoming adopters of heat pumps.