Welcome to this (very) longread! In order to guide you through all the different insights in the hydrogen chain I have divided it into chapters and paragraphs. Due to the many considerations discussed and information provided, it's likely that you will read it in stages. That is why there is a table of contents on the right hand side where you can click on any menu item at any time.
The first chapter of this long read is about the general EU vision on hydrogen. The second chapter is about the economics of wind energy and the economics of electrolyser systems. With help of these economics, I will explain how the economics of wind energy changes if you integrate wind turbine and electrolyser and transport the energy by pipeline.
The third chapter is about the user of hydrogen. It discusses the idea that hydrogen should not be used for heating houses or for mobility. And how it should only be applied in those sectors that are hard to decarbonise. The fourth and last chapter is about why current (proposed) EU policies are not working in favour for hydrogen as primary energy carrier. The concept of commercial readiness is introduced and why this is relevant for support schemes. A better definition of wind energy and hydrogen is provided. Last but not least a call to treat primary hydrogen likewise as primary electricity providing a level playing field.
With the recently announced program 'fit for 55' Europe is preparing itself to accelerate the energy transition. In the transition, the EU expects an important role for hydrogen. But the role of hydrogen is not as undisputed as it is for electricity.
The reasoning behind this is simple; 'Wind and solar supply electricity: 20% of the energy is lost if turned into hydrogen.' And 'Fuel cells have a lower round-trip efficiency than batteries.' A line of reasoning that seems to comply with the laws of thermodynamics, leading to the conclusion: 'We only need hydrogen when we can't solve it with electricity'. This conclusion translates into hydrogen priority ladders. The ladders provide guidelines on what situation to use hydrogen in.
Figure 1: The clean hydrogen ladder, source: Liebreich Associates
Or, to put it more simply, the general reasoning is: 'Electricity should be the primary energy carrier and hydrogen should only take this role when 'unavoidable.'' So, when electricity can't solve the needs, for example as a chemical feedstock in the industry. This vision on the relation between electricity and hydrogen is reflected in boardrooms of corporations like Volkswagen, Enel (world largest utility) and Tennet (Dutch electricity grid operator).
Figure 2: Tennet's (Dutch electricity Transmission System Operator) vision on hydrogen
It is also reflected in the EU policy of the fit for 55. Where hydrogen is 'only' given a role for those sectors that are hard to decarbonise. Hydrogen is not considered as a primary energy carrier like electricity is (yet!). The logic of the reasoning above combined with strong lobbies makes that this way of thinking is reflected in important legalisation. Legislation like (the proposed amends on the) renewable energy directive. It will also impact the announced delegated act. Restricting hydrogen production with complex additionality requirements. '
All these rules restricting hydrogen are the result of a fear. A fear that the conversion of electricity to hydrogen uses non-additional renewables. And thus, is cannibalising existing renewable electricity leading to more fossil-fuelled power generation. And thereby increasing CO2 emissions rather than reducing them. The fear is even so strong that in Dutch newspapers the use of hydrogen is called 'climate crimes' when hydrogen is utilised in transport and heating.
The argumentation is clear. The calculations are relatively simple and seemingly in line with the laws of thermodynamics. The climate needs to be saved, so why not restrict hydrogen production? Well, paraphrasing Einstein and Bill Clinton together says it all:
Let's start afresh with a deep dive into your look at wind energy. Let me explain why hydrogen is a much more cost-effective energy carrier for wind energy than electricity. I will provide insight into how economics influence the 'efficiency' of wind energy. And how these economics completely change if hydrogen is the primary energy carrier. I will explain how to yield twice the amount of energy per km2 sea with offshore hydrogen turbines than with electricity as the primary energy carrier. How this is cheaper per unit of energy. How a wind turbine and farm are set up nowadays, and how hydrogen can change their output and how this leads to a new view on using hydrogen in the transport and heating sector. I will also advise on how a level playing field can be created.
After reading this long read it is hopefully clear that the one-dimensional linear calculation 'wind to wheel' of Volkswagen is too simple. And with it providing wrong conclusions like in the hydrogen ladder of Michael Liebreich. I also hope you will see the role hydrogen can play in the energy transition.
How effectively does a wind turbine turn wind into useful energy? Few people realise that the amount of annually generated electricity by a wind turbine and/or wind farm is not merely a technical-mathematical outcome. It is an optimisation based on the costs and value of electricity. When designing a wind turbine and/or wind farm, the lowest cost and highest value per unit of energy is the primary driver, as opposed to maximal electricity yield.
Let us start with the fact that there is more wind at high altitudes. This is why wind turbines are made as high as possible. By increasing the length of the blades, more wind can be caught and economy of scale is created. The stronger the wind, the bigger the generator needs to be, to convert all the wind energy into electricity. The energy a turbine can yield increases exponentially with more wind. From 4 to 5 Beaufort the wind speed (in m/s) increases by ±40% but the potential energy yield increases by ±170%. Therefore, assuming a fixed length of the blades, the bigger the generator, the significantly more wind energy is converted into electricity. Especially on days with strong winds.
The size of the generator is not chosen based on maximal annual energy yield, it is chosen based on cost-effectiveness. By increasing the generator capacity, the cost of the turbine and all downstream transport infrastructure increases as well. The annual number of hours with strong winds decreases at some point. So, although the total yield increases with increasing generator capacity, at some point the marginal cost per MWh increases too, making the electricity more expensive. This is why the size of the generator is chosen such that it can make the most hours per year at full power, thereby reducing the average cost of the generated electricity. This results in a turbine that achieves its maximum rated power already at relatively low wind speeds. This means that with stronger winds there is no more electricity produced.
Due to this optimisation, the average cost price per MWh remains low and wind energy becomes competitive. A measure of how effectively a turbine converts wind into electricity is called specific power. This is expressed in W/m2: the generator capacity divided by the area of the circle, covered by the blades. The higher the specific power, the higher the energy yield in stronger winds.'
Wind turbine manufacturer Enercon used to supply the E-126 7.5 MW (601 W/m2). But this turbine is no longer available as the electricity it generated was too expensive. Nowadays the E-126 has a maximum power of 4 MW (321 W/m2). The difference in electricity yield per year: ±50%! (Depending on local average wind speed.)
Figure 3: Power curves of two wind turbine models with equal rotor diameter but differently sized generators, Source: Wind Turbine Models
The concept of full-load hours is confusing in terms of maximising energy yield. The logic is: the more hours a turbine runs on full load, the more energy is produced. The opposite is true about the efficiency of wind energy conversion. A large amount of full load hours means that the turbine reaches its full capacity already at low wind speeds. Resulting in significantly less energy production than technically possible.
The trend towards higher capacity factors (full-load hours) and lower power density has been going on for some time now. As demonstrated in the graph below, Figure 4, for the case of Denmark. During the recent annual event of the EERA JP wind conference, a special workshop was dedicated to the trend towards low specific power wind turbines.
In cooperation with TU Delft, HYGRO showed in a research project that hydrogen turbines will instead lead towards a trend of higher specific power. Simply because a lower levelized cost of hydrogen (LCoH) can be reached with higher power densities. And thus, lower full load hours. As a reference, the largest offshore turbine announced at the moment, has a power density of 342 W/m2.
Figure 5: Results of techno-economic modelling of hydrogen turbines with increasing specific power, decreasing the LCOH.
There are two other important economic drivers to keep the generator relatively small. On a windy day, all wind turbines generate a lot of electricity and therefore the value of electricity on the market is low. This is called the 'profile effect'. With an increasing share of wind energy on the market, the profile effect keeps increasing with it.
The other driver has to do with imbalance. Imbalance of a turbine is the difference between the predicted production (day-ahead prices and sold to the market) versus the real production of the turbine. The higher the specific power of the turbine (large generator relative to rotor diameter, thus high W/m2), the harder it becomes to predict the exact output. This is because the turbine follows every wind gust. This translates into imbalance costs in the electricity market.
The increasing cost of production at higher wind speeds, and at the same time the decreasing market value of this production, has a strong influence on wind turbine design.
In conclusion, for economic reasons, a wind turbine only converts a limited amount of the available wind energy into electricity. Or in other words, the efficiency of wind to electricity is much lower than is technically possible.
The same economic mechanisms are reflected in wind farm designs. An important cost element is the infrastructure. (Inter-array cables, transformers, grid connection, etc.). The cost of the infrastructure is determined by the peak power that the wind farm can deliver. If your turbines are positioned close to each other, they can still reach their peak capacity in strong winds. But in general, they catch each other's wind ('wake effects'), reducing the annual yield per turbine. So, the more turbines per km2, the higher the overall yield. But also, the higher the infrastructure costs and the lower the yield per turbine. This leads to an economic optimum for the distance between wind turbines and consequently the total energy yield of a windfarm.
When we talk about wind and sun energy storage, we usually mean electricity storage. Ideally, the energy is stored when there is a surplus and returned to the market at moments of shortage. The economics of storage only work if the cost of energy is low at peak supply (windy days) and high at moments of low wind. This creates a paradox with the design of wind farms; the higher the peak, the more costly the energy, while storage at peak requires low prices.
So please keep in mind; the amount of energy a wind farm produces is an economic optimum. And this optimum is motivated by the features of the electricity infrastructure and associated market rules and -mechanisms.
Due to market rules, a lot of the design optimisations are currently sub-optimal. Let's take a look at electricity storage at peak supply as an example. Electrical losses (heat) in cables increase quadratically with the amount of power that runs through the cable. Heat losses in an offshore wind cable can be as high as 10% of the total power output of the wind farm at its peak. If you want to store the peak electricity efficiently, store it directly at the turbine, not at the other end of the cable while losing 10% of your power.
In our current market model, energy transport losses are socialised. Producers do not pay the same (monthly) tariff for their (peak) grid connection as users of electricity do. This is an incentive to place the storage on the demand side and not on the (more sensible) production side. This relatively low cost of connecting renewable production to the grid is one of the reasons that the Dutch electricity grid is now overloaded. This creates major problems for the grid operators.
The grid connection costs for offshore wind energy in the Netherlands are also socialised. Due to the decoupling between wind farm design and infrastructure design, there is no direct mechanism that ensures an optimal integral design of both. Resulting in the risk of higher societal costs than necessary. Still, these costs are not in plain sight due to socialisation.
An important lesson from the current situation is that the optimisation of wind to electricity links to the economics of components, infrastructure, market, and regulations. To which extent can hydrogen change this optimisation of wind energy?
As HYGRO unveiled, hydrogen can change the optimisation of wind energy as well as our future energy system completely. Turbine, electrolysis, and pipelines provide such important synergy possibilities, that it makes much more sense to use hydrogen as the primary energy carrier for renewable wind energy instead of electricity.
For large scale wind farms, like offshore wind farms, it can be shown that twice (!) the amount of energy can be yielded per available space (km2) as compared to the current economic optimum for electricity. The so-called levelized cost of energy per MWh is lower than for electricity. The problem of reduced value on windy days due to profile effects and imbalance does not have the same impact as with electricity. Pipeline infrastructure offers buffer capacity and hydrogen can be stored relatively easily at an affordable cost in e.g. salt caverns.
I'll guide you through it. So, let's start by explaining electrolysis. Electrolysis is an electro-chemical process. With the input of electrical energy, it splits water into hydrogen and oxygen. This process takes place in what is called a 'stack'. It's the heart of the system. A stack consists of multiple sandwiched membranes and bipolar plates called Membrane Electrode Assemblies (MEA).
Electrolyser systems are assumed to be expensive. You will find in reports that the way to reduce cost is by economies of scale. It is therefore that you find plans for extremely large electrolyser facilities.
Figure 6: ISPT Hydrohub Innovation Program report, spatial planning of a GW scale electrolysis facility. Source: ISPT.
Interestingly the real cost reduction doesn't come from the scale of the facility. The cost reduction is primarily driven by automated production lines producing stacks. It's similar to solar, the cost of solar didn't come down by increasing the size of the panel, it came down through mass production. Companies like ITM and PlugPower (Figure 7) and others (Figure 8) are setting up manufacturing facilities, reducing the cost of stacks significantly over the coming years.
Figure 8: Current state of scale-up at major electrolyzer manufacturers. Source: GlobalData Secondary Research
An electrolyser stack is not the total system yet. To be able to produce hydrogen, additional components are required. Together, these are referred to as the Balance of Plant (BoP). This includes:
In general, water treatment, gas treatment and thermal management represent only a minor part of the total investment cost and are not expected to decrease in the near future. For power electronics, required for power conversion, however, this is not the case.
The stack needs to be fed with 'direct current' electricity. To get direct current for a grid-connected electrolyser system, you will need a grid connection, a transformer, and a converter. These components together form the power supply of the system.
As Figure 9 of a GW-scale electrolysis facility in the diagram above here shows, the stack (the heart of the system) is only a minor part of the total system. The total system is dominated by the electrical components required. In Figure 10 and Figure 11 below you will find the cost breakdown from two different reports. They essentially yield the same results. In terms of cost, the dominant factor turns out to be the power supply. It is good to notice that with the Hydrohub overview, only the cost from the 33 kV transformers and downward are considered. It's unclear why, but this might be because the transformation steps of 380 kV and 150 kV are costs for the grid operator and therefore socialized. The NREL cost breakdown is only given for a 1 MW system and therefore doesn't include the conversions from higher voltages either. As is clear from the figures, electrical components do make up a significant part of the total system cost when a grid-connected system topology is implemented.
The cost of the electrical components is not expected to decrease significantly into the future. This is because it is a technology that already exists for a while and is being mass-produced. However, the cost of electrolyser stacks will come down significantly, due to starting mass production and to further innovation. With decreasing costs for stacks, the electrical components and -infrastructure will become even more dominant.
Integrate electrolysis into wind turbines
So, what if we would skip as many electrical conversions, components and infrastructure as possible between the place where the electricity is generated, and where it is consumed. Let's say we integrate electrolysis into a wind turbine?
let's have a look at the turbine and start at the top, at the generator. The first component after the generator is a converter. It converts the variable alternating current (at the frequency imposed by the wind) of the turbine into a direct current. This direct current is then converted back into a decent 50 Hz frequency alternating current. Then, it is transformed to higher voltage levels, to make it suitable for long-distance transport. In the case of offshore wind turbines, quite often to 66kV at first and then up to 380 kV. When the electricity is brought onshore, it is subsequently transformed back to lower voltages, as shown in Figure 9 above.
In practice, a direct current is thus already directly available in the turbine! Why not skip all those elements in between generator and electrolyser stack and save a lot of costs? Not only a lot of cost of the components are saved. Also, every omitted conversion component means avoiding electrical losses as well. But that's not the only benefit of a direct connection between stack and turbine...
An electrolyser doesn't have 'one' single efficiency, it has an efficiency curve that depends on the amount of power ran through the stack. The less power put on the stack, the more efficient the production of hydrogen. This causes a positive correlation between 'the power curve' (the power output related to the wind) of a turbine and the electrolyser stack. At low wind speeds, the electrolyser efficiency will be higher than at high wind speeds. The long-term effect is that the average efficiency of the electrolysis coupled to a wind turbine is much higher than the efficiency at the electrolyzers' rated capacity.
Figure 12: Synergy of wind turbine power curve and electrolyzer efficiency curve
Earlier we showed that increasing the power density of a turbine leads to a decreasing Levelized Cost of Hydrogen (LCoH). If you increase the power density of a hydrogen turbine by increasing the generator size and matching the stack size accordingly, the average efficiency of the hydrogen production increases! This is one of the counter-intuitive aspects of hydrogen turbines that explains why a higher power density leads to a lower levelized cost.
When we produce hydrogen in a turbine, we need pipelines instead of cables to transport the energy. Interestingly, pipelines are 20 times cheaper than cables, when expressed as the cost of connected turbine capacity (€/MW). On top of that, pipelines offer inherent storage capacity since their internal volume acts as a mass buffer. This storage capacity can be utilized by varying the pressure, so-called 'line packaging'. For an offshore windfarm, the inherent energy storage capacity of the pipeline infrastructure has the energy storage equivalent of 250.000 Teslas.
Offshore electricity infrastructure has relatively high maintenance costs and is vulnerable to breakdowns. This is relevant for the security of supply. Furthermore, expected downtime plays a role in the yield and business cases of offshore wind farms. Pipelines are more robust than cables since downtime is essentially zero.
Now that we understand in more detail the optimisation of electrolyser and wind turbine, we can optimise the wind energy system for hydrogen. Even without making the complex calculations yourself, you will understand that the three important drivers (system costs, imbalance- & profile effects) are completely different for the design of wind turbines and -farms, that utilize hydrogen as primary energy carrier. Let's have a look.
By the direct integration of the electrolyser stack and generator, significant costs on power components are avoided. For both the electrolyser system and the wind turbine, the connection costs to the existing infrastructure are significantly lower. Furthermore, a lot of conversion power losses are avoided. Furthermore, by increasing the specific power, meaning, a bigger generator in relation to the length of the blades, the average electrolyser efficiency increases.
Modelling the interplay of these design parameters shows that the lowest levelized cost of hydrogen is reached at about double the specific power as compared to a regular turbine. At the same time, the cost per MWh is lower than for electricity and the energy yield for the turbine is up to 30% higher. Finally, the impact on the value of the produced energy (through imbalance and profile effects) is not as severe as is the case for electricity. Hydrogen is stored energy, the time constant from production to utilization offers entirely new logistical possibilities as compared to electricity since the grid balancing has to be instant.
Wind turbine manufacturers must redesign their turbines to achieve this 30% extra yield. An easier intermediate step is using current wind turbine technology and integrating the stack. This is a relatively simple adjustment, and by doing so, a lot of costs and power losses are avoided.
Based on these first versions of hydrogen turbines the redesign of entire wind farms can start. Due to the much lower cost of pipeline infrastructure, a new techno-economic optimum (lowest levelized cost per MWh) is reached at double the number of turbines per km2 sea when compared to regular turbines, increasing the annual energy yield with roughly 60%. Plus the cost per MWh of energy brought to shore is lower for hydrogen than for electricity.
If the increase in yield through turbine optimization(30%) and wind farm optimisation (60%) are combined in the future, this means a total increase of 200%.
Figure 13: Comparison of two wind-to-energy with the same amount of space available
HYGRO has performed several research studies (e.g. with TNO in the Netherlands and with Giner and NREL in the USA) and feasibility studies. This has led to a detailed techno-economic model in which we can vary all relevant technical parameters and costs. The model can compare two different hydrogen production systems: Hydrogen turbines vs electrical turbines with grid-coupled centralized electrolysis, based on the same assumptions.
Utilising the model we can optimise the Levelized Cost of Energy of the wind farm designs, taking into account complex non-linear behaviour such as wake-effects and including the behaviour and cost of infrastructure for the transport to shore. Thanks to our many partners our model uses cutting edge cost assumptions for technology that is ready for deployment today.
The first case study that was simulated using the model is the Dutch tender for Hollandse Kust West. What would happen if we make Hollandse Kust West a hydrogen wind farm? The basis for the calculation is the pricing of components expected for large scale application by 2025.
The outcome of the calculations is impressive. The energy yield can be 60% higher while the levelized costs of the energy transported to the shore are 5% lower. Compared to the scenario 'regular wind plus grid-connected centralised electrolysis' the outcome is even more striking: 40% lower levelized cost of hydrogen and 2.2 times as much hydrogen production, with less visual and spatial impact!
Figure 13: Energy cost comparison for Dutch offshore wind farm tender Hollandse Kust West delivering, from left to right: wind electricity, hydrogen trough wind electricity indirectly coupled to centralised onshore hydrogen production, hydrogen through wind electricity directly coupled to decentralised offshore hydrogen production.
The outcome of the modelling is not only impressive by its results. Discussions with engineering firms on how to pull this off show that with enough efforts by 2025 the first-generation offshore hydrogen turbines could be certified and ready for roll-out.
Unfortunately, the general belief is that hydrogen can't play a role before 2030 due to the unavailability of renewable energy to produce green hydrogen. All Dutch wind farms to be realised before 2030 and that are still to be tendered are focussed on electricity as an energy carrier only. The government should realise that they play an important role to speed up this development by making the tenders 'energy carrier neutral' or setting up new specialized 'offshore hydrogen' tenders in a short term. Hydrogen windfarms and hydrogen as the primary energy carriers will create also a different role for Tennet than is currently anticipated.
The benefits of direct hydrogen production utilizing hydrogen turbines are not only economical. The spatial and visual impact is very different from the case of electricity and grid-coupled centralized electrolysis. The landing of offshore power cables of the currently planned offshore wind farms already poses an enormous spatial planning challenge. This is due to the amount of free space the cables new claim, space that is required for other functionalities such as sand extraction and shipping routes. One can imagine that when the installed capacity of offshore farms in Dutch policy plans is 7 times higher than the currently planned, this problem will only further increase.
To transport electricity further inland, new high voltage lines are needed onshore. Along with space-intensive substations. The spatial and visual impact of pipelines is much smaller than for electricity. Last but not least, doubling the yield per km2 means also that less space is needed in the North Sea for the same energy demand.
Concluding: hydrogen is the most sensible primary energy carrier to produce and transport cost-effective and space-effective wind energy, electricity is not.
But even if you agree with this conclusion, you still might have doubts about hydrogen as primary energy carrier from the user perspective.
Figure 15: Comparison of two wind-to-hydrogen scenario's, using the same hydrogen demand as starting point
The argument against hydrogen is not only that it was inefficient and expensive to produce (which we have debunked), but also inefficient for the end-user. For example, a battery is said to have a 90% round-trip efficiency and fuel cell technology is only 50%. Especially regarding mobility, this argument against hydrogen is heard a lot. It is one of the reasons that in the EU REDII directive battery electrical vehicles are favoured (by a factor of 4). And for hydrogen, extra restricting additionality rules are defined.
So, let's have look at mobility as a potential end-user of hydrogen. Is this indeed as inefficient as claimed? When you dig into this matter, you will discover that the complexity is much greater than the simple round-trip comparison of 90% for batteries vs 50% for hydrogen. It requires another long read to cover all aspects, so in this blog, we will discuss only two aspects on a 'high level'.
To compare the efficiency of different types of vehicles, it is essential to understand that the most important variable for determining vehicle efficiency is the weight of the vehicle. The heavier the vehicle, the more energy it will consume per distance driven. To express the efficiency of mobility, one should measure the efficiency of the transported goods or persons in terms of MJ-ton/km or MJ-person/km. You can read in the following EU report why this is so relevant. Over the years vehicles might have become more efficient, but at the same time, we are all driving much heavier cars, increasing the energy consumption in terms of MJ-person/km instead of reducing it. This is despite the increased vehicle efficiency. When comparing battery and fuel cell vehicles, weight is a factor too.
It is especially relevant looking at the transport sector. Its purpose is to transport goods and in doing so, it consumes a major part of the total fuel consumption (primarily diesel). A well-designed fuel cell truck (or car) can have a much lower empty vehicle weight than its battery-powered truck equivalent. The impact of this is twofold:
For those thinking that this is not an issue for goods that are relatively light but require a lot of space; the efficiency in terms of MJ/ton-km is about the weight of the freight relative to the weight of the vehicle. The impact is as shown in the EU report, if you transport your family in a new but much heavier car then, despite the efficient new engine, the energy consumption potentially increases.
Does the difference in weight efficiency make up for all the round-trip losses between the claimed 50% for fuel cell electric vehicles and 90% for battery electric vehicles? That depends on many factors. It is a complex calculation with non-linearities throughout the whole chain, furthermore, it critically depends on the many different use cases. The graph below shows the impact of (only) two aspects of this comparison.
Figure 14: Comparison of different vehicle types, energy efficiency versus range. Source: RiverSimple.
The challenge in making accurate calculations on this matter is having a detailed yet generally applicable modelling tool. Comparing the same drive cycle and total freight to be transported. Be as inclusive of the whole energy system as possible. Consider logistical timing and peak effects and evaluate the suitability of an energy source in terms of location and available space. Don't simplify too much, there are quite some non-linear effects, creating tipping points that change the outcome significantly compared to simplified linear calculations. Be realistic on the different assumptions on the technology performance and do consider that both technologies are still advancing.'
These state of the fuel cell technology reaches already much higher efficiencies than the 50% often stated. And likely will exceed 60% or even more. The impact of these improvements is not always clear. An improvement of the absolute efficiency of a fuel cell from 50% to 60%, corresponds to a relative performance increase of 20%. 20% higher efficiency means either 20% longer range, or 20% weight reduction of the hydrogen storage on-board. 20% weight reduction increases the vehicle efficiency. Similar impact can be shown on the weight of the fuel cell system and its storage tanks where also technology is still improving. And yes, in a fair comparison, also the expected weight reduction in battery technology should be taken into account.
As stated, in fair chain comparison, all aspects of the energy chain should be taken into account. A complaint for hydrogen is that it not only in-efficient to produce, but if used for mobility you have to add compression and cooling losses. How much these losses are, depend on how you design the chain, the utilisation grade of the filling station and which technology advances you want to take into account. To cut the corner of another set of complexity here, these losses can be relatively small, not in the latter if you related them to speed of refilling. The speed of refilling is for many applications like heavy duty transport crucial for the cost in the business operation.
To be cost competitive, a heavy duty truck should be as much as possible on the road transporting as much as possible goods. A small battery pack can avoid the impact of the reduced payload. The range of the truck is than limited. To keep the truck as much as possible on the road, you have to charge regularly, ultrafast.
The challenge for a ultra-fast charging is that heat losses in an electrical system are quadratic with the power. That is why all super and ultra-fast charging facilities are liquid-cooled. And that is why battery manufacturers are innovating on heat management to deal with these peak charging losses (or equivalently peak discharging losses when driving fast) in the battery pact itself. And you have to take the impact of ultrafast charging even further down the energy chain. If you add ultrafast chargers within the current electrical grid without enforcing the grid, also within that part of the chain the energy losses will increase exponentially as well. Predicting the exact electrical losses of ultrafast-charging is, alike energy losses for hydrogen filling stations, very complex. To cut the complexity corner here as well, the 70% to 90% chain efficiency as Volkwagen shows on their website is optimistic, especially for heavy duty applications with ultrafast charging.
There is another complexity corner to cut. That is the complexity that the moment of (ultrafast)-charging is not necessarily the same as that of renewable production. Of course, with smart technology, this mismatch can be mitigated to a certain extent. In a fully renewable energy system, you need a considerable amount of buffering anyhow. But is especially true if you add a significant amount of opportunity ultras-fast charging that is driving by the need of the demand.
Witnessing the enormous price increase of electricity and gas due to the potential gas shortage coming winter is an example of the fact that timing in the energy system is crucial. In the energy system as we have today, the mismatch already has serious consequences. This despite the fact that our current system has intrinsically enormous (oil & gas) buffers built-in.
How much buffering to include, and which energy loss to address to the storage, is complex.
But sketching energy chain efficiencies without any buffering considerations doesn't provide enough insights to draw strategic conclusions on. But clearly hydrogen (pipelines) is a primary energy carrier and means of storage in one.
What the future exactly looks like is hard to predict and which energy carrier will prevail is to be seen. An indication could be the cost of the energy system. This difference concluded hundred years ago the so-called battle of the currents in favour for the more cost-effective solution, alternating current above direct current. As we showed in the first part of this long read, due to cost-effectives in terms cost per unit of energy and the space available, hydrogen is the preferred energy carrier for wind.
For mobility we can do the same kind of exercise. But now we start at the other end of the chain, a specific demand of goods to be transported. In the figure here below both options of wind to wheel, electricity vs hydrogen are plotted. Our conclusion, for hydrogen you need less vehicles, less energy infrastructure and less space for the energy production.
We are happy to debate this outcome with you!
Figure 15: Comparison of two wind-to-energy for mobility topologies with the same total energy requirement. (Left: Wind-to-electricity infrastructure, large space claim offshore & onshore, Right: Wind-to-hydrogen infrastructure, smaller space claim offshore & onshore)
Will hydrogen for heating still be a climate crime?
Hydrogen for heating houses was called 'A climate crime' and 'poor idea' in Dutch and UK newspapers. Let's be clear, of course, it is always better to reduce your energy need first. And yes, a heat pump makes sense to reduce energy demand. But what is the assumption about where the electricity for that heat pump comes from? And what are the costs of both energy infrastructure systems?
Let's start with some figures: The Netherlands has ± 8 million houses. A typical house in the Netherlands has an electrical grid connection of 6 - 17 kWe and a gas connection of 58 to 98 kW. The maximum peak load (including industry) of the national electricity grid is roughly 20 GWe (on average 2.4 kWe/household) and 350 GWgas for natural gas (43 kWgas/household). The design of the heat (gas) system is based on the prospects of a very cold winter, that you hope never occurs. A typical natural gas heating system in a Dutch household has a peak heat demand somewhere between 10 - 20 kW (gas). A heat pump with a COP of 4 could bring that peak down to 2.5 - 5.0 kWe, if and only if, during that cold day this COP of 4 can be reached. Increasing your electrical grid connection capacity for a heat pump will have a one-off cost of ±325 euro (excl VAT) plus a rough extra of 100 €/year. Leaving aside the costs for the grid operator to expand their local grid capacity required when every household in the street installs a heat pump.
The mass production cost for a mobility fuel cell system is targeted at ± 36 euro/kWe. We can assume that a smaller 'household fuel cell system' will have a similar reference cost at mass production. Supplying electricity to a 5 kWe heat pump with a fuel cell will then cost 180 euro. A fuel cell rated at 5 kWe electric power also provides about 5 kW of heat as well. This means a very high efficiency of the hydrogen used. 8 million households with each a 5 kWe system can provide 40 GW electrical power supply, twice the capacity of the Dutch grid.
The current vision is that for the energy transition we need to electrify many of our activities that currently are powered by oil or gas. The investment required in the Dutch electricity grid is assumed to be 102 billion euro in the next 30 years. That is 12.750 euro per household.
We can't predict the future. For an open debate it is not helpful by calling the use of hydrogen for heating, a climate crime. Up till now it leads to strategies and policies blocking efforts for a transition in this direction. To our opinion it can be a very efficient and cost-effective solution. What we need are policies that treat different energy system options as much as possible in the same way. By creating such a level playing field, the future will select the best options by itself.
Despite this long read, the discussion on hydrogen for mobility or heating will continue for a while. Being hard to decarbonise, the use of hydrogen in the industry is less disputed. As a policymaker, you might think that it is therefore safe to prioritise this application above the other sectors and avoid long debates. But then you will be soon faced with several new dilemmas.
Know that with the current state of technology (and without policy restrictions) the first offshore hydrogen wind farms can be realised from 2026 onwards. For a wind farm size of 176 km2, like the Hollandse Kust West (tender in 2021, realisation by 2025/26) the wind farm capacity can be 3.3 GW of hydrogen wind power. More than double the capacity (and 60% more yield at a lower cost per MWh landed to shore) than currently is being planned electrically (1.4 GW) (see also figure 13).
With a levelized cost of less than 1.65 euro/kg, landed onshore, hydrogen from wind should be able to compete with blue hydrogen. The current installed hydrogen production capacity in Rotterdam and Moerdijk area has a peak steam methane reforming production capacity of roughly 2 GW. This is an interconnected industrial area with the largest concentrated industrial hydrogen consumption (±45% of total demand) in the Netherlands. A 3.3 GW offshore hydrogen wind farm can supply up to 50% of the total yearly hydrogen demand in the Rotterdam and Moerdijk area. The challenge? Well, the mismatch between the 2 and 3.3 GW peak capacity and the fact that the hydrogen demand profile from the industry is rather flat throughout the year.
What is more cost effective, buffer capacity and/or demand -side 'management'?
A hydrogen wind farm can store up to 250.000 Tesla's of energy in its pipelines. That seems to be a lot. 'But related to the magnitude of daily production and fluctuations of the wind farm it is limited. In the wintertime, there is significantly more wind than in the summertime.
So, if hydrogen is only allowed (by means of restrictive policies) to supply to the industry, storage is an issue that stretches into seasons, making the required buffer very large. this is visible in Figure 16 below. The graph shows the required amount of storage when a hydrogen wind farm is forced to supply its hydrogen to the industry continuously, at the same rate throughout the year. Interesting to see in this figure, the difference in wind energy production per year, caused by differences in the amount of wind per year.
If the hydrogen also might be used for typical wintertime users like households. The required buffer capacity can change significantly. In Figure 17, you can find the natural gas demand for Dutch households over the year. What would you think is better? Restrict the hydrogen use for industry only and make sure you have sufficient storage? Or try to match supply and different forms of demand first reducing the need for storage?
Figure 16: Required buffer storage to cope with fluctuating H2 production profile if a flat-line demand profile is assumed.
We talk about large scale offshore here, but you have to start with this transition onshore. With smaller sized wind farms. Or even existing wind farms that can benefit from adding electrolyser capacity. In the early stage of development hydrogen gas pipeline infrastructure connecting dedicated to industrial areas are difficult to realise. Especially on a project-by-project basis. For smaller projects (single turbines), it is not even feasible. Especially if the cost of this infrastructure is not socialised as it is for electricity and natural gas.
So, in order to start with hydrogen turbines to gear up and scale up, industry is not necessarily the ideal user.
As most onshore wind farms are close to high-ways and business areas with a lot of transport demand, it makes sense to supply potential hydrogen produced therefore to the mobility sector first and make to the local heat demand secondary. But if policies are put in place that restricts the use of hydrogen for these applications, it becomes very hard to start this transition.
Commercial Readiness Level
For HYGRO, the insights presented above are within our DNA. We understand how hydrogen as primary energy carrier can bring significant advantages to the energy transition. Over the last five years, we have been on a mission to develop, build, and operate projects using all those insights to shape holistic energy value chains. The challenges we face are predominantly caused by the absence of an institutional framework. A framework throughout the whole value chain. Without a clear institutional framework, it becomes very hard to invest in these types of projects. The risk imposed on return on investment or even significant losses is rather high. This is blocking the development of hydrogen throughout the whole value chain for quite a while now.
'Institutional framework' is a container concept that entails many different 'soft' issues. Issues like norms, certifications, permits, tax, legislation, regulation, policies, and subsidies. The general impression of hydrogen is that it needs more technical development to become competitive. Or in technical terms, the Technical Readiness Level (TRL) is expected to be low. Yet, the challenge is not technical readiness. Most of the crucial components are ready (TRL8/9) for serial production. No, the real challenge is the low Commercial Readiness Level (CRL). This is an assessment tool used in Australia, that gives insight into the non-technical challenges of new technology. The EU has a whole set of categories for grants and subsidies to support innovations and sustainability. In 2021 the categories for innovation and climate and energy are being revised. The revisions clearly improve the supportive potential for hydrogen. Nevertheless, also in the revision, there is no clear description of what low commercial readiness of technologies entails. This leaves a vacuum of support for the development stage of technologies with a high TRL and low CRL. A strong recommendation to EU and other policymakers would be to implement the concept of CRL for support of innovation. This will help to avoid a too strong focus on TRL levels only.
The overarching challenge for 'hydrogen' is that it covers new value chains. Investments in parts of the chain can only be viable if all other parts are viable as well. This problem is often referred to as the chicken and egg dilemma, who comes first? But it's not a chicken and egg. The most important part is to make sure the final user understands the benefits and has a clear business case.
For example, we can look at Switzerland. There, zero-emission heavy-duty vehicles are exempted from significant road taxes, making hydrogen trucks competitive with diesel. This created a demand for up to 1.000 vehicles, to be rolled out in 4 years. Almost automatically making it viable to organise the total value chain. And as you can see from the interviews with the drivers of the trucks, they like the convenience of the trucks. As the Swiss example shows, a single policy measure can enable a whole value chain for hydrogen. But analysing the Swiss example, it is also a bit of luck. In the past, there was already a high road tax for trucks. Introducing the exemption was relatively easy.'
On the EU level, there doesn't seem to be such a 'single easy' policy measure to influence hydrogen markets. As is clear from the EU fit for 55 plans. On 12 different directives or regulations, changes are planned. All directly or indirectly influence the degree of deployment of hydrogen.
Looking at the many different new policies on fighting climate change, the optimist sees a lot of traction for hydrogen. But all these policies are full of complex and restricting measures for hydrogen breaking the traction. This breaking energy for hydrogen stems from the general view of hydrogen being the inefficient conversion of electricity. '
Due to the intuitive conception that sun and wind energy generate electricity as primary (and thus preferred) energy carrier, all policies and legislation start with the definition that wind (and solar) energy 's electricity. This makes renewable hydrogen secondary, by definition. It is literally what one can find in, for example, the EU taxonomy;
Or in the definition of the EU hydrogen strategy (page 3);
If the EU uses the above definitions of hydrogen then it becomes impossible, at least by law, to yield more energy from wind or sun with hydrogen as primary energy carrier. This neglects the fact that the magnitude of energy production is an outcome of the economics of an energy system.
These definitions make hydrogen a secondary energy carrier by default. And it is therefore automatically treated alike in all legislation. A clear example is the Renewable Energy Directive II (RED II) which doesn't treat hydrogen the same as electricity. But before diving into that, to be clear, the EU should distinguish two forms of hydrogen production. The key distinguishing factor being that the electrolyser is part of the wind turbine or wind farm and located at the same geographical position. This, as opposed to the concept of not being connected to the electricity grid or a so-called 'direct line'. Therefore, the two forms of hydrogen production:
Define renewable hydrogen as a primary energy carrier, just like renewable electricity. Apply this equality throughout all the different directives, legislations, creating a level playing field. Hydrogen as a primary energy carrier will then take a very fast and high flight. It will become one of the major energy carriers for the energy transition since it is a cheap form of renewable energy with a limited spatial impact as compared to electricity. The energy system as a whole will become more robust, due to the high reliability of pipelines and since hydrogen is a form of chemically stored energy that can be buffered and offers new time constants for logistic optimisation.
This is it for now. Hopefully, you have the same sense of urgency after reading this blog concerning hydrogen as we have. Thank you for your time and please let us know your thoughts or questions. We will be happy to hear them.