Methanol’s Surprise Rise & Hydrogen’s Decline In Dutch Scenarios – 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 second half of our conversation. The first half is available here.

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]: Welcome back to another episode of Redefining Energy Tech. I’m your host, Michael Barnard. As always, we’re sponsored by TFIE Strategy, which helps firms, startups, and investors spend big climate action money faster and more wisely. This is the second half of my conversation with Emiel van Druten and Paul Martin regarding the Netherlands target grid scenario for 2050, which we worked on recently for a week. Emiel is a market energy scenario modeler for the Netherlands transmission operator Tennet, which brought Paul and me in to assist. Paul, of course, is the founder of Spitfire Research, a chemical engineer with decades of experience designing and prototyping modular chemical process plants for clients globally. He’s also co-founder of the Hydrogen Science Coalition.

I’ll be speaking to the head of Octopus’s building side in the UK on the 17th. He published something a while ago called Fabric 5th, which attracted a lot of zeal from the Fabric First crowd. I’m talking to him because I published something very similar a few weeks ago and ticked off the usual suspects—the passive house crowd.

Paul Martin [PM]: It’s very similar to the discussions you hear about electric vehicles. You get the crowd that says electric vehicles aren’t sufficiently better to make enough of a difference, so we have to redesign our cities, move everyone onto active and public transport, and rely on electrified high-density mass transit. And yes, we have to do all of that.

But we also need electric vehicles because those changes will take a long time—seventy years and trillions of dollars. The same is true with the built form and fabric of buildings. You’re not going to knock them all down to grade or completely gut their interiors, insulate them, and replace all the windows and doors just to transition away from dirty combustion heating. You’ll make those changes when the time is right and in ways that make more sense.

[MB]: Especially because induced demand is a factor with building envelope improvements. I looked at research from multiple continents over the past 25 years. I had already known about the UK study of 55,000 homes, which found gas usage returned to exactly what it had been before after two to four years. That was an extreme example, but I also examined case studies in North America and elsewhere. They all found the same pattern. The best-case scenario was only a 50% reduction in natural gas use.

My thesis has always been electrify first, with fabric improvements in support of electrification within the available budget. That’s where I stand, and that’s what we were discussing in this context. It’s fascinating to watch these dynamics play out. 

Emiel van Druten [EVD]: I wouldn’t go that far. Insulation does help, because it allows you to size your heat pump a bit smaller and avoid wasting extra capital on equipment. 

[MB]: But that’s for the budget. That’s the point. For the budget you do just enough to make it worth electrifying. 

[EVD]: Yes. You insulate your roof from the inside. If you have an uninsulated cavity wall, add cavity wall insulation. Make sure you have underfloor insulation. That’s what you need—you don’t have to put on a whole new façade to achieve that. 

[MB]: I don’t care about that from my perspective, because a person can choose to spend more on energy. What matters is that they’re using electricity and low-carbon energy. 

[EVD]: In this space I’d like to mention Heat Geeks, a YouTube channel from the UK. They spend a lot of time on this and recently expanded into the Netherlands with a branch of their own. They have installers, and they run a course that teaches them the basics. Those who complete it get a label as Heat Geek–approved installers. They also put metering on their heat pumps and share the data on an open platform, heatmonitor.org, where there’s even a leaderboard showing who can create the most efficient installation.

What they emphasize is that it all comes down to balancing three things: the size of your heat pump, the building fabric, and the heat transfer capacity. If those are in balance, you have a good design. That’s what you need. The current focus only on fabric leaves a big blind spot. 

[MB]: And as we come back to the scenario planning, there’s a lot to pull apart, but it was a really good process. The PESTEL [Political, Economic, Social, Technological, Environmental, Legal] approach was a solid framework. Cross-societal input from DSOs [distribution system operators], the transmission system operator, the gas transmission operator, and industry groups were all part of it. But our reflection was that there was parochialism and siloing in some of the contributions. Industry would say, “Here’s what we’re doing,” and that was it. The most striking example was a firm that, when asked to consider four scenarios, said, “You want me to do something for those four scenarios? Well, this is the only thing I’m going to do.” And that’s exactly what they delivered.

 [PM]: “We’re growing in all four. Yeah, we’re growing in all four. That’s the only one we’re going to consider.” You can understand why they say it, but you don’t believe them. 

[EVD]: That’s actually a bit like what we heard from Tata Steel. They said, “No matter what the world looks like, we’re going to do hydrogen DRI in all scenarios, in all storylines.” We showed you their green steel plan. They have a two-phase approach. Right now they operate two big blast furnaces, and they also pollute the neighboring village, so there’s a lot of scrutiny. They want to clean up their act.

Their plan is to first tear down one blast furnace and replace it with DRI—direct reduction of iron—running on natural gas with CCS. That feeds into the DRI unit. After that, they can make virgin steel from iron ore and melt it in an electric arc furnace.

The second phase shifts to green hydrogen DRI, and then by 2040 or later, they want to convert the first unit to fully green hydrogen as well. The picture then is two DRIs on green hydrogen and electric arc furnaces running alongside.

The question we asked was whether this makes sense—not just as a technology, but here in the Netherlands, given that offshore wind is already being pushed quite far out, 200 kilometers at 50 meters depth, which is becoming more expensive. Does it make sense to do it here? 

[MB]: The first thing to understand about Tata Steel is that it’s a specialty steel manufacturer producing high-end steel. It ships product all over the world for premium applications, including specialty alloys. It’s probably one of the highest-margin segments possible, but it’s not positioned well for minimizing costs. Strong top line, mediocre bottom line.

The second point is that Paul and I have both been digging into steel for years. I’ve built a steel projection through 2100 and recently revised the demand profile. China is facing declining cement demand as infrastructure build-out slows, and alongside that comes declining steel demand for infrastructure and buildings. About 50% of all steel goes into buildings. As building demand falls, so does steel demand. That’s not high-value steel—it’s mostly rebar—but it’s a lot of volume.

The same dynamic that drives cement demand down will drive steel demand down. China accounts for half of total global production and demand for both, so its trajectory pulls the whole market. At the same time, scrapping is increasing. China is shifting toward scrap-based steel. Europe is finally ending the export of 20 million tons a year and moving toward more scrap recycling and electric arc furnaces, aligning more with the United States. And here I’ll give my rare plug for the U.S.—70% of its steel has been made with electric arc furnaces since 2000. That’s the direction the world is heading. 

[EVD]: So your point is we need less virgin steel. 

[MB]: We need less virgin steel. We need the specialty steel. And Tata is well positioned for the specialty steel, but it’s not going to be made with hydrogen. 

[PM]: And the Netherlands is the wrong place for direct iron reduction using green hydrogen. It will be cheaper to do it elsewhere in the world, so we don’t see that second phase happening. 

[EVD]: But the first phase, what was your opinion on it? 

[PM]: The first phase already assumes carbon capture and storage, with enormous investment going into it. Feed it green methane, biogenic methane—there’s enough of that available—and use CCS to make it carbon negative. Don’t bother with pure hydrogen DRI. It essentially becomes a standard direct iron reduction unit, which has been in production for decades in many places around the world. You just change the feedstock and apply CCS to the production emissions. That seems quite reasonable.

As for phase two, if it happens, it will likely mean building electric arc furnaces in the Netherlands, but feeding them with direct reduction pellets produced elsewhere in the world, where energy costs are lower and there aren’t competing customers for electricity. 

[EVD]: So it only makes sense to have an electric arc furnace and feed it a mix of scrap and imported green iron. 

[PM]: Yeah, or hot briquetted. 

[EVD]: Yeah, whatever. Doesn’t matter. 

[PM]: Whatever comes next, you produce it in parts of the world that can do it at low cost because they don’t have customers for electricity—which isn’t the case in the Netherlands. If the Netherlands ever has large amounts of excess renewable electricity, there’s a ready market in Germany and neighboring countries. That sets a floor price because there’s always an export option.

In places like Chile or Western Australia, there are no customers for that electricity and no export market. The cost is simply whatever it takes to produce it. That’s why they turn to DRI, ammonia production, or similar pathways—to monetize the energetic asset they’re generating. Those are the regions where this will be least expensive, though still costly compared to what we’re used to. 

[EVD]: There’s a good study by Tom Brown and Fabian Neumann from TU Berlin on Europe’s energy import position in a decarbonized future. They show that producing virgin steel in Europe is the most expensive option. Ammonia can be done, particularly in places like Spain, but virgin steel is by far the hardest thing to produce competitively within Europe. 

[MB]: Well, doing anything with hydrogen that you don’t have to do with hydrogen is always the most expensive way to do something. 

[PM]: Right. And it’s important to make a clear distinction. People like to oversimplify and use neat labels, but stop calling it green steel. What we’re really talking about is the iron reduction portion, separate from the steel production portion. Electric arc furnaces are already at Technology Readiness Level 9. In the United States—which has its own struggles acknowledging climate change and dealing with it from a policy perspective—electric arc furnaces dominate simply for cost reasons.

So the steelmaking part is already electric, and it’s reasonable to expect it will continue without much difficulty. The real issue is iron reduction, which is where these companies are focusing their efforts.

[EVD]: Eighty percent of the energy demand is in iron reduction. The arc furnace is just a small portion. 

[PM]: Exactly. But that iron reduction is going to happen in parts of the world where it makes sense. Steel production, on the other hand, even though it isn’t the biggest energy consumer, is where the labor is, where the jobs are, and where local market supply matters. You don’t want to ship large structural steel members long distances if you can avoid it. The same goes for lower-value products like rebar—you want them going directly from production to use with minimal transshipping.

So it makes logical sense to keep steelmaking local but move iron reduction to places where it can be done at scale and at lower cost. 

[MB]: I’d characterize it a bit differently. Multiple technologies for new steel are emerging. DRI with hydrogen is not TRL9. DRI with biomethane is TRL9—it’s already being done today. If you have large sources of waste biomass producing anthropogenic biomethane, you can put that into biodigesters, generate green methane, and feed it into the DRI system.

One thing I found is that the direct reduction process is exothermic, so much of the process heat comes from the chemical reaction itself. You only need to add about 20 to 25% of the heat. With hydrogen, though, you have to provide all of the heat for the DRI, which makes hydrogen DRI even less economically viable. 

[PM]: It’s actually an area where I’m consulting with people on high-temperature industrial heating done electrically. In the conventional process using synthesis gas made from methane, the carbon monoxide–iron oxide reactions are exothermic and balance the hydrogen–iron oxide reactions, which are endothermic. The result is a process that’s almost thermally neutral.

If you switch to pure hydrogen, you have to add a lot of electric heating. And this isn’t heating at a couple of hundred degrees Celsius—it’s heating at around 900 degrees Celsius. That’s not easy. It’s possible, but very challenging. 

[MB]: The champagne of hydrogen for the heat. 

[PM]: The DRI guys aren’t even thinking about that. If you’re doing pure hydrogen DRI, you’re doing electric heating—that’s a certainty. 

[MB]: As we went through this, one of the conclusions we reached—along with representatives from other organizations—was that we don’t see a role for hydrogen in steel. In the Netherlands, there’s an opportunity for green methane by capturing biomethane emissions and applying carbon capture to create negative-emissions specialty steel. That’s what Tata can pursue.

Any place in the world with significant waste biomass and a CCS opportunity has the potential to make negative-emissions steel, which is a real advantage. 

[PM]: And if CCS isn’t available, and it’s biogenic, just vent the CO2. It’s not the end of the world. 

[MB]: We’ve eliminated the methane problem—the anthropogenic biomethane from waste biomass—and turned that methane into an economically useful product.. 

[EVD]: And this is just for phase one. Once you’ve used up your potential green methane budget, if you want to do more, you simply import intermediate green iron. That was also our conclusion for the other industrial sector. 

[PM]: Correct. 

[EVD]: We went through all of them. Take fertilizer. We have a big fertilizer industry here because we had cheap natural gas. That meant cheap gray hydrogen—or other “colors,” blacker than black. With cheap natural gas, we could produce a lot of ammonia. But that won’t be the case in the future. Spain, Morocco, Australia—those will be much better locations to make green hydrogen and ammonia. And ammonia is easy to ship compared to hydrogen. So if we want to keep fertilizer, that’s the context we’re dealing with. 

[MB]: You want to use ammonia as a feedstock, mostly for fertilizer or explosives. Yes. But as an import for energy, no. As a carrier for hydrogen, no. 

[EVD]: So what we concluded is that if we want to keep the fertilizer industry, it will import ammonia directly and use it to make fertilizer. The same applies to chemicals—no synthetic fuel production.

There were a lot of ideas in the scenarios, including direct air capture and synthetic fuels for the chemical industry using green hydrogen. But the consensus was clear: this won’t work, and if it does work anywhere in the world, it definitely won’t be in the Netherlands.

That said, there are domestic sources worth using—waste plastic and waste biomass that can be gasified. As Rainier explained, you can gasify that and produce methanol, which can then be converted to olefins. Olefins are the base chemicals for many high-end products. We have a large plastics sector with many high-end jobs, and we should keep that sector—but without pursuing synthetic fuels. 

[MB]: I would say methanol was the surprise winner for me out of this week. This is the first time I’ll say it publicly—though I did mention it once on LinkedIn. Biologically sourced methanol is probably going to be the shipping fuel of the future. 

[PM]: To put it the way I did during the discussions: the options for long-distance transoceanic shipping and aviation are all poor. They’re all expensive, all limited in feedstock to some degree, and tied up in food-versus-fuel concerns. There are also national and international issues that arise when developing countries start exporting things like palm oil. It’s a big, messy, unpleasant problem.

But from a chemical engineer’s perspective, when you compare aviation fuels and shipping fuels, something becomes clear. Aviation requires a very specific suite of molecules—a narrow composition that must be met. No one is going to build a new generation of aircraft engines designed for something else when airframes last more than 20 years. That constraint is immovable. Right now, fuel is about 20% of an airline ticket’s cost, which means there’s room for the airline industry to pay more for decarbonized fuel.

That’s not the case in shipping. For shipping, fuel accounts for around 40% of operating cost per ton-mile. 

[EVD]: Shipping is a bit like trucking—it’s low margin. 

[PM]: They can’t afford a specific molecule, and as a result, whatever parts of shipping can’t electrify—which will already drive costs down—will just have to accept what’s available. And what’s available is methanol. They could also use ammonia, but that would kill people. I’m not on board with solving climate change by killing people just to save a buck, because that’s literally what we’re talking about. Ammonia is off the table for safety reasons—any chemical engineer who understands the basics of safety and design would reach that conclusion. You’d have to be seduced by a lot of money to think otherwise.

That leaves shipping with methanol, while aviation takes the easier-to-convert feedstocks. For example, vegetable oils that can be hydrotreated and hydrocracked to the right fuel composition. 

[EVD]: It actually took us a long time to reach a conclusion, and at first people weren’t fully understanding each other. To get there, we had to map everything out on a big whiteboard and ask: what do we actually have here?

We identified three basic forms of bioenergy to start with. First, fatty oils like vegetable oils and used cooking oil. Second, general biomass and waste streams that can be gasified to make methanol as a starting point or intermediate, which can also be imported. Third, ethanol from sources like corn or sugarcane. The EU isn’t supportive of ethanol for fuels because of the food-versus-fuel issue, so that option is off the table.

That left the other two. Methanol can be burned directly in ships, which is straightforward. It can also be converted to olefins and then olefins to kerosene for aviation. But even then, you can already see how many steps are involved. 

[PM]: Too many—far too many steps. 

[EVD]: It’s going to drive costs up. With fatty oils, you can use a hydrotreatment process with hydrogen and steer it in different directions. You can make more HVO biodiesel or something closer to heavy fuel oil for ships, or you can steer it toward mostly kerosene for sustainable aviation fuel. That process can be adjusted fairly easily, and kerosene is the most logical outcome.

The supply is limited, but if this is the cheapest route for aviation, aviation will simply outprice shipping. That was our conclusion—and that’s when Michael flipped his position. 

[MB]: That was the switch that did it for me. We have this limited amount of feedstock, and it’s the cheapest option that will work for aviation.

[EVD]: It’s the cheapest option for everyone, but for aviation the second-best alternative is such a big step down. 

[MB]: For aviation, they need the end product that’s easiest to make from that feedstock, so they’ll pay more than shipping can for HVO. Shipping won’t be able to compete on price. Once I understood the economic price signal and the merit order between those options, I realized there isn’t enough to go around—even in my projections, which already show a significant reduction in maritime shipping and a much flatter trajectory for aviation.

That has an important corollary. I already project 100% electrification of inland shipping and almost all short-sea shipping, with hybridization for transoceanic shipping. Electrons are going to be much cheaper than biomethanol as an energy carrier. 

As soon as hybridization takes hold and batteries become dirt cheap, ships will start using larger batteries to extend their range and optimize costs. That leads to a significant increase in electricity demand from the shipping segment. In the national scenario, we went from 2% of electricity for shipping and aviation to 12% by 2050. And that’s not an endpoint—that’s simply how much could transition within that timeframe. 

[EVD]: And that 12% is mainly from short-haul flights within Europe, which will electrify first. The interesting part with methanol is that at the beginning of the session I asked you about long-haul transoceanic shipping and whether you saw potential for battery electrification there. You said maybe 2% in the long term. But once you realized ships won’t run on HVO and instead on methanol, which is more expensive, then maybe it’s not 2% in the long term. Maybe it’s 10%, 20%, even 30%—we just don’t know. 

[PM]: But higher, and I completely agree. I think many people don’t realize how strong the driver will be for extending electrification in both shipping and aviation once the very significant cost increases hit for anything even remotely low-GHG. Biomass pathways can be labeled low-GHG by definition, but on a lifecycle basis they aren’t really that low today. That highlights a major problem we have to solve—decarbonizing agriculture—because we need to eat, and if we intend to use agricultural waste residues as fuels, they must actually be low-GHG. But we have to decarbonize agriculture anyway, regardless of fuels.

So we end up solving several problems at the same time. The economic pressure to electrify will push things further than expected. I think we all strongly agree that all land transport—anything with wheels—is going electric. 

[EVD]: That was already in our baseline scenario, except for trucks, where 10% were assumed to be hydrogen. We asked if that made sense, and the answer was no. Even the last 10% will go electric. So 100% of trucks go electric.

Today we’re recording this podcast at Johnny Nijenhuis’s, who is an advisor on electric trucks. He’s been saying the same thing for years: no diesel trucks will be sold after 2035. Early on he looked at both hydrogen and batteries, but he quickly realized it would only be batteries for everything on wheels, including heavy trucks. People often say heavy transport is hard to decarbonize, but if you look at shipping, the bigger the ship, the larger its carrying capacity. That means the biggest ships are actually the easiest to decarbonize, since the batteries only take up 1–3% of the ship’s volume and weight.

The challenge isn’t technical—it’s economic. Those batteries cost billions of euros, making it a capex problem rather than an engineering one. 

[MB]: The 2022 study published in Nature by Berkeley Lab—which I’ve discussed with two of the three researchers—basically concluded that with battery prices at $100 per kilowatt-hour, it’s the cost, not the mass or the volume, that becomes the constraining factor. 

[PM]: It’s dollars per kilowatt-hour that drive shipping’s electrification, and it’s energy density per unit mass and volume that drives aviation.

Both of those are improving—steadily improving—but not fast enough to say with 100% certainty that by 2050 we won’t still be building ships crossing the Pacific on combustion fuels. I think we’ll still see a substantial number of methanol-burning ships.

[MB]: Absolutely. My view now is that the end state will likely be Atlantic shipping going 100% electric, and possibly making it 50% of the way across the Pacific. Those are very long hauls, but ships will be maximizing electron use through hybridization. 

[EVD]: And you’re much more bullish than the sector. You talk to them, and we also spoke with people at the Port of Rotterdam. They really don’t see this happening at that scale. They’re installing megawatt chargers now, but they call it shore power—just for stationary ships, keeping appliances running while docked. They haven’t realized yet that ships themselves will be powered by batteries, and that it’s going to be big.

As both the TSO and the DSO in that region, we have to start planning for it because it will be significant. I think it will follow the same path as trucks. When Johnny started talking about big electric trucks 10 years ago, and Auke Hoekstra said they would happen, everyone dismissed them as fools who didn’t know what they were talking about. But they actually did the numbers and proved it worked. Everyone who said it couldn’t be done, that it was too heavy, was just speaking from gut feeling.

The same thing will happen with shipping. In five years people will say, “Remember when Michael and Emiel said on that podcast that shipping would be battery-electric?” And by then everyone will be purchasing electric ships. 

[MB]: It’s like we were talking about mining earlier with Fortescue. They’ve put about $3 billion into electrified heavy mining equipment, converting everything in the mines, including massive bulldozers and dump trucks that dwarf a human. That’s a clear sign of where we’re heading.

Every so-called hard-to-electrify transportation sector is being knocked off one by one. And everyone who says it can’t possibly be electrified is being proven wrong, one by one. I just see that as inevitable. 

[PM]: The economic driver is really clear, and it’s not just about operating expense for energy. There are many other advantages. We don’t need to beat that point to death. But one area we hadn’t fully discussed was what to do about materials and chemicals. 

[MB]: Before we get into that, I just want to say one last thing. I left Thursday afternoon beaming because I’ve had a heterodox projection of global hydrogen demand declining for years. I’ve been the only one asserting it’s going down while everyone else has been saying it’s going up. 

[EVD]: Michael Liebreich’s scenarios say hydrogen demand is going up. And the Netherlands does use a lot of gray hydrogen in industry because of its history—big chemical fertilizer production and heavy refinery use, especially for desulfurization. In most scenarios, the projection is for even more.

But when we did the numbers and looked at each individual sector, asking what really makes sense, we ended up with hydrogen only in refineries and in biorefineries, which we’ll get to in a minute. That remaining hydrogen demand doesn’t increase compared to today—it decreases. 

In our scenario, hydrogen demand decreases by 80%, largely because we lose the ammonia industry.

Not for transport—there’s no transport application—and we also lose ammonia for electricity generation backup, since we have green gas instead.

[MB]: Not for green steel or green iron. Across all these demand sectors, the only two major growth areas I projected for hydrogen were green iron—40 million tons per year by 2100—and hydro-treating biofuels, at about 4 million tons. 

[PM]: Well, let’s be clear—the Netherlands isn’t going to be making that green hydrogen. It will come from somewhere else. 

[EVD]: Yeah, we’ll import intermediates like ammonia or green iron. But we’re not going to import hydrogen as liquid hydrogen or anything like that. What we worked out is that the amount of hydrogen we need can be supplied with 3 gigawatts of electrolysis. And while that sounds like a lot, the scenario had more than 30. 

[MB]: That was being generous about electrolysis. I don’t think we need that many. 

[EVD]: But in the scenario you proposed, there were over 20 gigawatts of offshore hydrogen production. Paul, you even talked about a chemical plant offshore. 

[PM]: I’m still scratching my head at how anyone in their right mind thinks they’re going to save money on cables by building electrolyzers offshore to pump hydrogen. On no level does that make sense. I was very glad to see that idea dropped because it’s pure fantasy, disconnected from economic reality. You don’t build things offshore if you can build them onshore—you just don’t. And you certainly don’t do it to save on cables. That’s nuts. 

[MB]: Yeah, I know. So let’s pivot back—we’ve only got a few minutes left. Let’s turn to the chemical industry, Paul’s raison d’être. 

[PM]: I think a lot of people believe we have to transition away from using petroleum for anything. I’ve never been one of them. If we’re sensible about end-of-life use of materials and chemicals, we can continue making them from petroleum—and we will, because it’s the cheapest way to do it.

Now, to be clear, the cost of doing so—completely electrifying a refinery, eliminating fuel gas, and finding alternative ways to handle waste products from refining steps with low GHG emissions—is technically possible but very expensive. Still, it’s trivial compared to trying to use biomass. Biomass has a high oxygen content that has to leave as either CO2 or water, with significant energy losses.

The likelihood of moving from petroleum, which already has carbons and hydrogens in the proportions we need, to biomass, which comes with excess oxygen we don’t need, is very low. Our scenario planning ended with methanol produced in two ways. One is for olefins to make chemicals and materials. That can come from the non-biogenic portion of waste materials, including waste plastics—though issues with additives, contaminants, and heteroatoms in plastics are very real and need to be dealt with. If that’s solved, waste can provide part of the methanol supply.

The methanol used in ships and other combustion applications will be biogenic and largely imported.

[MB]: And for the fossil fuel industry here, about 15% will persist, but only for petrochemicals, not for anything that’s burned. There’s another key consequence that affects hydrogen demand. As we move into a world where we’re no longer burning massive amounts of fossil fuels, oil demand won’t require refining the dirtiest feedstocks—like heavy, high-sulfur crude from Alberta, Mexico, and Venezuela. 

[EVD]: Oils that require a lot of hydrogen for desulfurization. 

[MB]: I did the math on it, and a Schlumberger person confirmed the numbers. It’s about 7.7 kilos of hydrogen per barrel of Alberta’s oil, compared to 2.3 kilos per barrel of light sweet crude. That lighter crude is what will be flowing into Rotterdam on tankers and feeding the petrochemical industry. It won’t be a huge hydrogen demand area. 

[EVD]: The assumption you proposed was that per barrel of oil, hydrogen use for desulfurization would be cut roughly in half because we’d start with cleaner crude. Once we finished working through refineries and chemicals, we had all demand sectors covered, including industry. On the last day of the workshop, we balanced it out—especially electricity demand. We had higher demand in aviation, shipping, and to some extent households, but we removed a lot of electrolyzers and direct air capture. The net result was a significant reduction in electricity demand compared to the starting assumptions.

We began with a scenario where electricity demand was expected to grow fivefold relative to today. Where we ended up was three-and-a-half to fourfold growth. That reshaped the supply side focus. We concluded that not all offshore wind and nuclear would be needed to meet demand. Solar and onshore wind should stay, since they’re cheapest. Far-offshore, deepwater wind becomes expensive, and nuclear is the most expensive and not cost-optimal. The view was that nuclear could be pursued if government insisted, but it would be limited in scale. As for offshore wind, the capacity dedicated to offshore electrolysis was cut, leaving 50 gigawatts out of 70.

Originally it was a net electricity-importing scenario to make molecules and export them again. That didn’t make sense. With a large North Sea, the Netherlands should be an exporter of electrons to neighbors like southern Germany, which lacks sufficient domestic capacity to decarbonize its economy. From a fairness perspective, sharing that advantage makes sense. So with 50 gigawatts of offshore wind, the Netherlands could be roughly net neutral. With 55 gigawatts, it could export tens of terawatt-hours to its neighbors—which feels fair.

That’s where we ended up on the supply side. 

[MB]: In the end, hydrogen demand plummets. No nuclear. And all of this was based on the economics. We’re at the end of the hour and a half, and it’s been a great discussion. I always leave time for an open-ended observation from my guests—something they’d like to share with the audience. So why don’t we start with Paul and close with Emiel. Paul, what open-ended thought would you share with the audience at this point? 

[PM]: I would just say that Canada is ripe for this kind of analysis, and it needs to happen sooner rather than later. Being a federation of provinces, there’s a lot of regional variation. But if we could do something like this—model it properly and get serious about our path forward—we’d be much further ahead in our decarbonization journey. I would love to see it happen. 

[MB]: Well, just as I’m assisting the Netherlands and Ireland, I’ve also been asked to help with something an executive I know—who’s well connected—is trying to initiate for Canada. I’ve already done a 2050 decarbonized Sankey for Canada, so hopefully that will evolve into something where I can actually be a prophet with honor in my own home. 

[PM]: I hope so. 

[MB]: Emiel, Open ended. 

[EVD]: I have a shout-out that might help answer your question. It’s a tool we used during our process: the open-source website energytransitionmodel.com. It’s an open-source energy model where you can adjust each subsector. We used it during our workshop because it’s the same model we use for our scenarios. You can go into the industry subsector—say, steel—change the assumptions, and within seconds the model recalculates the entire energy system on an hourly basis. It then updates the results and graphs for that sector and the whole economy. It was a lot of fun to use.

We’ve been working with that model for years and know all the fine details, but I could see that you hadn’t seen it before and yet found it intuitive—just making changes and seeing what happens. All European countries are included in the model, and other TSOs in Europe are starting to adopt it. So maybe you could ask them to build a Canada model.

[MB]: That would be good. This has been Redefining Energy Tech. I’m your host, Michael Barnard. My guests today have been Paul Martin and Emiel van Druten. We’ve just spent a week helping Tennet, the transmission system operator in the Netherlands, figure out what 2050 is going to look like. And I’ll just say—it’s much more electrified than even they expected. Until next time, thank you.