50 years of green hydrogen failure

 From Michael Liebreich.

It is over fifty years since Japan's "Sunshine Project" started governments pouring money into green hydrogen as a replacement for fossil fuels. How is it going? TLDR: not well.  That’s why it’s called the #HydrogenSoufflé.

I don’t even need to write a commentary - I’ll just leave you with five charts:

• We’re not producing green hydrogen (despite the investment
• We’re not buying hydrogen vehicles (despite the hype)
• We’re not buying hydrogen fork lift trucks (despite the rumours)
• We’re not buying hydrogen trucks (despite the hopes)
• We’re not buying hydrogen boilers (despite the grift)

Hydrogen is hard to store, because its small molecules can escape through metal and plastic molecules of its container.  It makes pipes brittle.  It needs to be chilled and compressed for storage, so there are energy costs/losses.  And in most cases, alternative technologies are cheaper and more effective.  For example, the round-trip efficiency of lithium-ion batteries for storage is much higher than electrolysing water and then using the hydrogen in a fuel cell.  For aircraft, the hydrogen has to be kept at  -253 C as a liquid or at 5,000 to 10,000 pounds/per square inch (350 - 700 bar, 1 bar equals one atmosphere).  Tricky.  It can be used to smelt steel, but that works best if the hydrolyser is close to the steel mill.  And as I've mentioned often before, if it is converted to methane by the Sabatier process, it can be used for long-duration storage for balancing the grid.

In my opinion, and obviously also Liebreich's, green hydrogen is mostly hype.  Green methane, maybe.  And as the first chart shows,  only 0.1% of hydrogen produced is in fact green.

Why Europe never has blackouts

 A most interesting analysis.  He shows that without wind and solar, even with maximum demand in mid-winter, the electrical grid in Europe can still cope.  He discusses storage (pumped hydro, with batteries growing fast) and the trans-Europe grid.

He makes two points.  The first is that solar is never zero during daytime, but wind can be zero for a prolonged period.  This means that Europe will still have to "burn things" to make sure it always has enough power.  This implies long-duration storage, if they are not to use gas. He mentions synthetic gas, but doesn't go into detail.  He may mean green hydrogen, or synthetic "natural" gas (green methane) made from green hydrogen via the Sabatier process.   

It seems to me that Europe needs to add more solar from sites in Southern Europe (Spain, Italy, Greece, etc), as solar's winter lows can be compensated for by excess capacity and its nighttime absence by storage.  

Making hydrogen electrolysers super efficient

The traditional electrolysis process is relatively inefficient.   If you use surplus green electricity to produce hydrogen and then burn the hydrogen to make electricity, its round-trip efficiency is low, much lower than alternative energy storage techniques:

 

Flora noted that converting power to hydrogen and then using the fuel to generate power has a relatively low round-trip efficiency. Round-trip efficiency is the percentage of electricity retrieved after being stored.

The technology to convert power to hydrogen and back to power has a round-trip efficiency of 18%-46%, according to data that Flora presented from the Massachusetts Institute of Technology and scientific journal Nature Energy. In comparison, two mature long-duration technologies, pumped-storage hydropower and compressed air energy storage, boast round-trip efficiencies of 70%-85% and 42%-67%, respectively. Flow batteries, a rechargeable fuel cell technology that is less mature, have a round-trip efficiency of 60%-80%. 

(Source: S&P Global --- Hydrogen technology faces efficiency disadvantage in power storage race
)

[Incidentally, Elon Musk claims that's Tesla's lithium-ion batteries have a round-trip efficiency of 93%]

But an Australian start-up, Hysata, is developing a process which enormously increases the efficiency of electrolysis.    I've already talked about this company and their super efficient hydrogen electrolyser, here.  

This update is from ARENA (Australian Renewable Energy Agency)

A pioneering, all-Australian hydrogen electrolyser technology is getting the chance to prove itself at a commercial scale.

If it works, the project has the potential to transform the economics of renewable hydrogen production.

ARENA’s support has helped develop this new technology since it was a concept in a University of Wollongong laboratory. That work saw a spin-off company, Hysata, established to commercialise the development.

Now, Hysata will receive $20.9 million ARENA funding as part of a $47.5 million project. Hysata will build and test a 5 MW system at its new Port Kembla manufacturing facility.

The plan then is to move the entire system to Rockhampton in Queensland, for installation and trials next to the Stanwell Power Station.

Queensland government-owned power company Stanwell Corporation is providing the site and facilities, and also backing the project with $3 million.

ARENA CEO Darren Miller says the project is a crucial step to enabling purchase orders for the technology.

“Hysata’s electrolyser technology could be a game-changer for renewable hydrogen,” Mr Miller said.

“The demonstration at Stanwell’s site will be key to unlocking commercial demand for Hysata’s product by proving the technology works at scale.

Currently, the production cost of renewable hydrogen (using renewable energy) is at least twice that of hydrogen produced from fossil fuels. Hysata says its technology will slash costs and produce hydrogen “well below” a competitive target price of $2 per kilogram (approx. US$1.50/kg).

FYI, if there’s one number you should remember, it is that price of $2 per kilogram. That’s the key to competing with fossil fuel-derived hydrogen and fully unlocking renewable hydrogen’s industrial and energy future.

It’s all in the bubbles.   All electrolysers work by passing an electric current from electrodes through H2O – water. The current splits the water into its two parts, hydrogen and oxygen. That process takes energy.

Now, if the entire process were 100 per cent efficient, all that energy would go into splitting the water. Nothing else.

But, until now, electrolysers have also produced a lot of heat. That’s because, just like an electric heater at home, they have electrical resistance.

The heat generated is not only wasted energy, but it must also be removed. Electrolysers need a lot of cooling and that uses even more energy.

So, if you can reduce resistance, a greater proportion of energy is available to split the water. Also, the system generates far less far less heat, which in turn requires less cooling.

Hysata has tackled the problem by completely redesigning their electrolyser to remove all the main sources of electrical resistance.

It turns out, that means eliminating hydrogen and oxygen bubbles. When bubbles form on the electrolyser’s electrodes, they reduce the surface area available for electrolysis and increase resistance.

In fact, Hysata says it has completely eliminated bubbles from its system and cut electrical resistance to virtually zero. As a result, Hysata says it expects a fully operational electrolyser will stay cool through good air ventilation alone.

The combined effect is what has raised the overall efficiency of a Hysata electrolyser to around 95 per cent. That’s a huge jump on current technologies, which operate with efficiencies closer to 75 per cent.

To put that in context, to make renewable hydrogen competitive with its fossil-fuel derived alternative, the International Renewable Energy Agency (IRENA) in 2020 set an electrolyser efficiency target of up to 85 per cent … by 2050.

I'm not sure that hydrogen by itself is in fact the future.   To transport it, you need to compress it and refrigerate it, which takes additional energy, further reducing its round-trip efficiency.  Also, it makes gas pipes brittle, and, because its molecules are so small, it easily escapes through the gaps in the molecular lattices of gas pipes or storage tanks.   But if you convert it to methane, using the Sabatier process, it's the equivalent of natural gas, and in fact is called synthetic natural gas (SNG, which is a bit of an oxymoron, no?)  And then you can use the existing gas distribution system and gas storage system, as well as existing gas turbine electricity generators.  On the other hand, to make SNG, you need a source of CO2, and unless you use the escape gases from a gas-turbine power plant flue, you have to produce CO2 using direct air capture, which is still very expensive.

We will need seasonal (or long-term storage)  to reach 100% renewables, and hydrogen, or more probably, SNG, will be how we fill that gap.  So, if this can be commercialised, it will be a huge step forwards towards a 100% green energy system. 

Opinions about solar --- Jenny Chase

From a toot thread by Jenny Chase (who works for BNEF)  My comments are inside square brackets, like this: [...].

Time to make 2023 updates to my annual “opinions about solar” thread.

If you like these, the second edition of my book, Solar Power Finance Without The Jargon, comes out very soon (just sent final proofs to publisher!)

https://www.worldscientific.com/worldscibooks/10.1142/q0437#t=aboutBook

https://www.amazon.co.uk/Solar-Power-Finan

It's the book I should have read before trying to get a job in renewable energy. Edition 1 was “too valuable, and entertaining, to be ignored” according to PV Magazine. I rewrote Edition 2 quite a bit after the 2022 energy crisis, and included a lot more batteries and hydrogen.

I did this thread once a year on X, now branching out. You can view the 2022 thread below, and from there it links to 2021, 2019, 2018 and 2017.

https://twitter.com/solar_chase/status

1. To opinions! Solar is the cheapest source of bulk electricity in many countries, and the quickest to deploy, and now you couldn't stop it being built if you wanted to.

The limits to PV build in most places are grid access, permitting, and sometimes installation labour.

2. We don’t need a solar technology breakthrough. Today, solar developers just need a grid connection and permission to sell electricity, and then they’ll be off building solar plants whether it’s a good idea or not.

3. Right now the price of solar modules hits a new record low every week (currently $0.136/W) due to oversupply. Some manufacturers will exit in the next two years.

This is quite normal in this industry, and nobody will learn any lessons from it. Good for buyers, though.

4. Incremental improvements in solar modules continue. 2023 was the move from PERC cell tech (module efficiency ~21.3%) being the standard design, to TOPCon (~22.3%). The average solar module in 2023 was about 21.6% efficient, up from 15.4% (a now-obsolete multicrystalline design) in 2012.

5. In October 2021, when the standard mono module price was 27.3 US cents per W, I said it would "come back down over 1-2 years" (referring to all-time low of 19 cents in summer 2020). Since it’s now 13.6 US cents in normal markets (ie not the US or India), I’m going to say that wasn’t too bad a prediction.

6. India and the US have solar import tariffs, so modules are pricier there (~23 and ~33 cents/W respectively). Both countries are subsidizing local manufacturing capacity. This is a perfectly good strategy as long as it doesn’t slow down their energy transition.

7. Thank goodness we’ve collectively stopped the nonsense of boasting about "lowest ever solar auction prices", most of which were Middle East opaque transfer prices or had other features. PV power prices below $25/MWh unsubsidised are still too low. Solar still does cost money.

8. After grid and land, the next big challenge for PV will be power price cannibalization. Basically, PV plants in one area all generate at the same time. This means that they reduce the price of power at that time, “cannibalizing” their own revenues.

9. High PV build resulting in power price cannibalization also affects other power plants, but not as much as it affects solar, because solar plants generate most at times when solar is pushing the price down most. This will hold back more solar.

10. By 2030 most countries will have spot power prices of zero for a few hours every sunny day. This will be passed on to end consumers, to encourage them to shift power demand to sunny periods by electric vehicle and battery charging, preheating, precooling, etc.

11. It may well be that "negative power prices for a few hours every sunny day, followed by high evening power prices when the sun goes down" is a problem solved by capitalism and batteries.  [In other words, utilities/generators will make money by topping up the batteries at midday and discharging at the evening peak.  This may apply to EV owners too]

12. Utility-scale batteries became a thing much faster than I expected. BNEF's Energy Storage team recorded 16.8GW/32.9GWh of gross energy storage capacity additions worldwide in 2022, and expect 41.9GW/98.6GWh in 2023.

13. Small-scale batteries are a thing too, even though the economics don’t always make much sense. 2023 battery attachment rates – proportion of residential PV buyers who get a battery too – are >70% in Germany and Italy, >50% in Switzerland, >30% in the UK. [Depends of the difference between retail and wholesale electricity prices. For example, I'm paying 50 cents/kWh for electricity from 3 pm to 10 pm, while my feed-in tariff is just 11 cents/kWh]

14. I'm more worried about seasonal intermittency than daily, because there is no way we can build a big enough battery to shift energy from summer to winter. The economics of battery storage are impossible at one cycle a year.  [See my pieces on seasonal storage]

15. We oughtta be building more wind. Seriously, PV will get built anyway, but wind needs help, and wind blows in the dark and in the winter. It doesn’t help that solar pushes down power prices and generates renewable energy credits, which hurts wind farm economics.

16. To put it another way: when you tell an energy future model to optimise a power portfolio for clean power adequacy, it will give you more wind and less solar than when you tell it to optimise a least-cost electricity sector development.

17. BNEF's mid cumulative solar forecast is 5.8TW by 2030, above the 5.3TW that BNEF models that we need to be on a global net-zero-by-2050 high-renewables path. Wind is 1.9TW forecast and 3.6TW net-zero pathway, so a big miss.

18. Hydrogen made with renewable electricity will be used for steel and fertiliser manufacture. Some may be made into ammonia for shipping and aviation fuel. Some may even be burned for power in weeks of low renewables, which is one way to shift energy from summer to winter. [Hydrogen is hard to store and transport---converting H2 to methane via the Sabatier process is prolly a better way to go]

19. ...but sometimes net-zero electricity models want to put in hydrogen to cover weeks of low renewables just because the model isn’t given any other option. Deep decarbonisation models do weird things. It may turn out there are easier pathways in practice.

20. Electrification of transport is far better than biofuels; for example, as Dan Lashof says on this podcast with @drvolts , it would take about 300 acres of farmland to run a petrol car on corn ethanol, vs an electric car running on about one acre of photovoltaics.

https://www.volts.wtf/p/whats-going-on-wit


21. Decarbonizing aviation is hard. The CEO of Lufthansa said in September that running its fleet on sustainable aviation fuel made from electricity would take half Germany’s current electricity demand. BNEF thinks this an underestimate.

22. However, BNEF research did track orders for 989 electric aircraft (mostly small ones) as of early 2022. Fingers crossed.

(Paywall source for the 989: https://www.bnef.com/insights/30267 )

 

23. Heatpumps are better for heating homes than hydrogen, but in seasonal climates like northern Europe will exacerbate the seasonal demand and supply mismatch for solar. [Use green methane]

We need to build wind and probably nuclear as well.  [Yes, nuclear in high latitudes may be necessary]

24. Nuclear is safer than coal and climate change, and better than gas unless the gas plants are running very rarely. Batteries should help with the unfavourable ramping economics of nuclear (you *can* turn nuclear plants up and down, but you really don’t want to).  [Nuscale maintains that their SMRs can be easily ramped up and down] 

25. We’re finally getting serious about net zero carbon. Getting that last 10-30% of carbon out will be hard, and require some expensive solutions. The first 70-90% is easy-ish but we're getting on with it.

26. You can be cynical about government and corporate net zero emissions targets if you like, but they're a lot better than no net zero emissions targets.

27. Ordinary people have no idea how much progress we’ve made. Tell people at parties that in 2022 renewables produced 47% of Germany’s electricity. [South Australia 68% in 2022; should reach ~90% by 2026]

28. The 2022 energy crisis should put most concerns about cost of renewables subsidies to rest; renewable energy saved Europe billions of euros in imported gas, and reduced purchases from Russia. Turns out fossil fuels also cost money, and sometimes, unexpectedly, a lot.

29. Sorry for the German, but this chart is “the development of renewable energies in primary energy consumption in Germany” and it shows a. overall primary energy consumption (not just electricity) falling and b. renewables rising. This pattern is seen in many developed economies.

https://www.bdew.de/service/daten-und-graf

30. …It would still really help if rich people would stop pissing away carbon for no reason. [Yes]

31. The US Inflation Reduction Act includes a licence to print money for solar manufacturers and hydrogen firms.
It’s good for clean energy, but it's also like hitting the accelerator on a car with the handbrake on. The handbrake is trade barriers, grid and permitting issues.

32. US trade barriers on Chinese solar are great for First Solar, which also receives 17 cents/W for its US manufacturing, and also for southeast Asian firms like Boviet and VSUN, and Indian firms like Waaree and Adani.

33. The supply chain for solar manufacturing should probably be more transparent.

This sentence is also true without the word “solar”.

34. While moving to a circular economy with 100% recycling rates is essential in the long run, it’s not a challenge for PV in particular; few PV panels have been recycled to date only because the vast majority are still in use. It can be done.

35. For 5 years I have been refusing to get excited about perovskites until a perovskite company can disclose a commercial partnership with a named major module manufacturer. They have now. Still not excited. Just big manufacturers trying to look like they have an edge, I reckon.

36. Europe will support its solar manufacturing industry with grants, but not with trade barriers. This makes sense. The grant-backed factories are small, but are insurance against a huge disruption to the international supply chain.

37. Solar manufacturing is a horrible business to be in. Competition is vicious, the newest factories have the best tech. Older manufacturers carry heavy debt for factories rapidly becoming obsolete.

38. Floating solar is a thing, but it’s not a new tech. It’s solar onna boat.

It’s mostly about having a place to put the modules and, when it’s on a hydro dam reservoir, a grid connection right there. Grid connections are like gold dust.

39. Agrivoltaics, likewise, is solar onna field.

PV only has synergies with some crops. Competition for light and restricted mechanical access to crops are often problems. Study is needed to avoid just subsidised bad PV and bad farming in the same place. 

40. Batteries for residential solar systems are becoming standard offers. Frankly some of the sales claims are of indifferent veracity and the current software isn’t up to economically optimising when batteries charge and discharge. Buyer, be aware you may not save a lot of money.

41. Also get your rooftop solar system built when you have scaffolding up for something else, 'cos scaffolding is expensive. Ideally build it when you’re building the roof, there will never be a better time. Rooftop solar mandates are good and should be more common.  [We don't use scaffolding in Oz]

42. Anyone buying a new internal combustion car now is pretty silly. EVs aren’t the answer to everything – especially congestion of cities – but they do use much less energy and, with flexibility, can support the grid.

43. If you get a battery and a solar system, pay attention to when it charges and discharges and what power costs at those times! Everyone needs a hobby.

(We need better control software for residential solar and storage to use consumer flexibility to support the grid. Norway has it already, houses pay a price linked to the current spot price of electricity and you can set an app to charge your electric car when it expects to be cheapest in the next x hours!)

44. Very few people who are not solar project financiers understand tax treatment for solar projects (I don’t) and it’s important enough to make most calculated LCOEs irrelevant to power purchase prices.

45. Solar thermal tower and heliostat designs, especially with molten salt storage, are still not working very well. We might even end up using molten salt for multi-day and seasonal storage... but heat it with PV.  [Vast Solar in South Australia may be different]

46. Solar plant operation and maintenance in desert environments will prove more challenging than PV project stakeholders currently expect. Climate risk from hurricanes, hailstorms, fire and floods is on the rise for solar as for everything else.

47. Traded electricity wholesale markets are the worst way of deciding how to dispatch energy resources, except for all the others that have been tried.

48. Many solar project developers complaining their problem is 'finance' are being disingenuous. Their problem is, their project is rubbish and they cannot convince anyone otherwise. This is not just a solar thing.

49. Auctions for renewable power are getting a lot more complex, and that’s good. India’s 24/7 auctions and China’s energy megabases are a fascinating way to try to solve grid issues by co-locating solar, wind, storage and even fossil plants.

50. South Africa will hopefully be a case study of a major market where solar helped to solve a crippling power crisis. About 5GW of solar will be installed this year, much of it on homes and businesses. [The Zimbabwe model is worth looking at]

51. Watch Nigeria, which recently removed subsidies on gasoline and hence made the country’s ~50GW of private generators much more expensive, for how cheap solar and batteries could play out in other African countries. Could they really leapfrog straight to clean power?

52. There is enough land for lots of solar. There are enough golf courses in the U.S. for about 370GW, ffs. There’s also loads and loads of roofs, so let’s see those who oppose ground-mounted solar support higher-cost roof-mounted solar. [Over the last 12 months, rooftop solar has provided 20% of South Australia's electricity, and utility-scale solar just 6%]

(sorry going off on a slightly tangential rant about how hard my job is)

53. Forecasting solar build is hard when people actually pay for the results and therefore want them country by country. It’s easy when you just extrapolate a global line, but that is not terribly useful for setting corporate strategy, and makes your clients yell at you.

54. You want to forecast a terawatt-per-year solar market by 2030, you go for it! (We have 707GW/year in 2030). Fair warning, you’ll have to forecast solar build in markets that currently have no plausible plans, and where country experts will tell you it will never happen.

55. In 2017, my analysis team covered 42 countries which were significant solar markets. Now we attempt to cover 146, which is a pain, and we keep finding ones we have missed.

56. Also have I mentioned how bad the data is?! Increasingly nobody knows where the bloomin’ solar panels are being installed. We have Customs data on how much is leaving China, and it’s a *lot*, but it is often unclear where it went.

57. While in theory you can see said solar panels from SPACE, in practice it is far harder to count them by machine learning than you might think. You can waste a lot of time preparing training data and get clearly inaccurate results for area covered. I am told.

58. If you record PV capacity and only have room for one figure, record MW(DC), the module capacity. It tells you more about what the project will produce, how much land it needs, and what it will cost than MW(AC), which is just the size of the wire.

I will die on this hill.

Also btw if you want to estimate a rough capacity factor for an entire country, just use an insolation map, not a really hyperspecific tool. PVGIS has some great ones. {Link here]

That's all, apologies for spamming Energy Mastodon.

If you would like a less flippant primer on solar and the future of decarbonization (though it still has jokes), do check out edition 2 of Solar Power Finance Without The Jargon. Also if you’re a journalist wanting to review an advance copy of edition 2, please let me know. Shouldn't be long now, I approved the final proof!

The hydrogen furphy

I've been suspicious about the hydrogen mania for a while now.   Michael Liebreich does a much better demolition job than I could.   But his recommendation to use green ammonia, made from green hydrogen, for long-term storage in electricity generation is very interesting.   And I don't share his doubts about using e-fuels for jets.  If e-fuels cost twice as much as jetfuel, so be it.  We survived without intercontinental jet flights before, and we could again.

[From BNEF]

By Michael Liebreich

Senior Contributor
BloombergNEF

Injecting some reality

Two years ago, BloombergNEF published my two-part primer on hydrogen, Separating Hype from Hydrogen. On the supply side, I was optimistic: green hydrogen (produced from renewable energy) would over time become cheaper than blue hydrogen (produced from natural gas but with carbon captured) and eventually cheaper than gray hydrogen (produced form natural gas without carbon capture).

On the demand side I was more skeptical. While clean hydrogen will be needed to decarbonize a number of use cases in industry, and perhaps for long-duration storage, I found it hard to identify any role for it in applications like land transportation or space heating. Since then, as I have done more work on industrial heat, I have even come to believe it has a limited role even there.

If my intention at the time was to inject some reality into discussions about hydrogen, I clearly failed. Rhetoric around hydrogen has become ever more overblown.

According to lobbying group the Hydrogen Council, citing a series of reports commissioned from McKinsey over the past three years, hydrogen can be expected to contribute more than 20 percent of emissions reductions needed for the world to reach net-zero emissions – a figure repeated by politicians and journalists seemingly without the slightest critical examination.

German Chancellor Olaf Scholz has called hydrogen “the gas of the future” and promised “a huge boom.” Japan’s Prime Minister Fumio Kishida has declared that “shifting to and developing a hydrogen society is critical for achieving decarbonization.” Frans Timmermans, the EU Executive Vice-President for the European Green Deal believes that “hydrogen rocks.” Jacob Rees Mogg, briefly UK Secretary of State for Energy this year, called hydrogen “the silver bullet”.

Public money is starting to flow. The EU has approved the first 13 billion euros ($13.7 billion) of the 430 billion euros ($450 billion) promised under its 2020 Hydrogen Strategy and is now working to launch a “Hydrogen Bank”. The US Inflation Reduction Act (IRA) provides a ten-year tax rebate per kilogram of green hydrogen worth $3, which will soon be more than the production cost itself. Free hydrogen anyone?

Of supreme import

In October this year the Hydrogen Council and McKinsey released another report entitled Global Hydrogen Flows, predicting long-distance transport of 400 million tonnes of clean hydrogen and its derivatives (calculated on a hydrogen-content basis) by 2050, out of total global production of 660 million tonnes of hydrogen. It is worth bearing in mind that today, 94 million tonnes of hydrogen are used annually, virtually all of it made from fossil fuels, creating 2.3% of global emissions. The vast bulk of today’s hydrogen never leaves the compound on which it is made, let alone cross an international border.

The idea of hydrogen imports as a way of decarbonizing major industrialized economies is enormously seductive – so much so that Germany and Japan have made it central to their decarbonization strategies. Here’s Japanese PM Kishida again: “Japan aims to commercialize an international hydrogen supply chain by producing hydrogen in bulk at low cost in countries blessed with bountiful renewable energy resources coupled with marine transport infrastructure.”

Chancellor Scholz is promoting hydrogen imports not just as a way of decarbonizing the German economy, but as a replacement for Russian gas. In August he and Canadian Prime Minister Justin Trudeau flew to Newfoundland and Labrador to sign an agreement to “create a transatlantic supply chain for hydrogen well before 2030, with first deliveries aiming for 2025”. As I write this, German Economy Minister Robert Habeck is on a five-day trip to Namibia and South Africa to secure hydrogen supplies.

The problem with this vision of large-scale imports of hydrogen is that the physics of hydrogen is unlikely to play ball.

The unbearable lightness of hydrogen

In February this year, Kawasaki Heavy Industries’ Suiso Frontier arrived in Kobe, Japan carrying the world’s first ever cargo of liquid hydrogen from Australia. Did this momentous occasion herald the start of a brave new world of trade in liquid hydrogen, as the press coverage suggested? In a word, no.

Set aside the A$500 million ($334 million) cost of the project; set aside the fact that most of the hydrogen on board the Suiso Frontier was made from coal; and set aside the fire that broke out on board while loading. The 1,250 cubic metres of hydrogen carried by the Suiso Frontier contained just 0.2% of the energy content of a single large LNG carrier. Okay, the first ever LNG cargo, carried 63 years ago from the Calcasieu River on the Louisiana Gulf to the UK, consisted of a similarly picayune 2,475 tonnes. Surely liquid hydrogen can be scaled up in the same way as LNG has been? Kawasaki Heavy Industries, builder of the Suiso Frontier claims it has already lined up the first order for a much larger, 160,000 m3 carrier from Nippon Kaiji Kyokai.

This is where the physics of liquid hydrogen step in. Although the scaled-up vessel would carry 60% of the volume of an LNG Q-Max, it would carry only 22% of the energy.

Hydrogen has very good gravimetric energy density – the amount of energy carried per unit weight. On this measure, hydrogen beats diesel, petrol and jetfuel by a factor of around three, and LNG by a factor of 2.7 – which is why it makes a great rocket fuel. However, it has very poor volumetric energy density – the amount of energy carried per unit volume. It’s worth remembering that while a cubic meter of water weighs 1,000 kilograms; a cubic meter of hydrogen weighs only 71 kilograms.

On a volumetric basis, hydrogen’s energy density is a quarter that of jet fuel, and only 40% of that of LNG. Since ships are volume constrained (think Suez Canal, Panama Canal, etc.), this inevitably means more trips. Even if Kawasaki Heavy Industries was to scale its hydrogen carrier to the same size as a Q-Max, it would need to make 2.5 deliveries to carry the same amount of energy as one cargo of LNG. You don’t need to know anything at all about shipping to know that 2.5 times the trips are going to cost you 2.5 times as much.

But this is only the start. A liquid hydrogen carrier will inevitably be more expensive than an LNG carrier. Its load will be at -253C instead of -162C, and all pipes, valves, pumps and tanks have to resist hydrogen embrittlement. And because liquid hydrogen is both colder and lighter than LNG, the liquid hydrogen ship would have up to nine times more boil-off en route (these ships let some of the load boil off as heat enters the tanks, and then use that as fuel for their engines), unless you add either much more insulation or a complex cryogenic recycling system.

Overall, you would be wise to assume that the seaborne segment of your hydrogen trade will cost around four times the cost of LNG per unit energy.

It’s the physics, stupid

But that only deals with the seaborne segment. We still have to talk about liquefaction and regasification.

Liquefying hydrogen is a is a hugely energy-hungry process, made complex by the quirks of hydrogen physics – things like its negative Joule-Thomson Effect (unlike most gases, hydrogen gets warm when it expands and cold when compressed) and ortho-para isomer conversion (without which liquid hydrogen re-evaporates, irrespective of insulation). Liquefaction of hydrogen currently consumes 30-40% of its energy content, versus no more than 10% for LNG. Ways to improve this are being researched, but nothing can change the fact that liquefying hydrogen is, quite simply, a bear.

As for regasification, again the plants will be more expensive than for LNG. They need to operate at lower temperatures; all valves, pumps, pipes and tanks have to resist embrittlement; and compressors have to be of larger capacity because pressurizing hydrogen gas requires more work than pressurizing natural gas. European politicians, scrambling to build new terminals to receive LNG in replacement of Russian gas, are suggesting that these terminals will be repurposed to receive hydrogen or its derivatives. This is nonsense. You can re-use the docks and infrastructure, and any distribution pipelines can be upgraded, but 70% of everything else has to be scrapped.

In summary, while LNG approximately doubles the cost of gas delivered by pipeline, shipping liquid hydrogen will cost four to six times more than LNG. In other words, you can’t power an economy on imported liquid hydrogen, and that is not because of things that can be fixed – scale, technology, cost of capital and so on – but because of the underlying physics: volumetric density, liquefaction temperature and interactions with other materials.

It’s a gas, gas, gas!

If importing hydrogen in liquid form is out, what about importing hydrogen as a gas?

Here, things look much better. Gaseous hydrogen is already transported by pipeline – all the pipes, pumps, valves and tanks need to be appropriately engineered, but the economics are not terrible. Just as well, given the volume of hydrogen we are going to need at industrial “hydrogen hubs” for industrial uses and to provide long-duration back-up power.

Just replacing the current production of gray and black hydrogen would create demand for 94 million tonnes of clean hydrogen. Pipeline imports are well-placed to meet a decent proportion of this.

There is, however, a caveat. The longest natural gas pipeline in the world (excluding side branches) is Brazil’s National Unification Gas Pipeline (GASUN), just under 5,000 kilometers long. In their report on hydrogen trade, McKinsey and the Hydrogen Council predict 40 hydrogen “trade routes” connecting the globe. Those serving Europe by pipeline from Norway, North Africa and the Gulf are certainly feasible (the one from Russia is clearly off the cards for decades). However, none of the longer trade routes linking the US West Coast with Asia, the US East Coast with Europe, or the Gulf, Africa or Australia with Asia are likely to carry a single cubic meter of gaseous hydrogen.

There are a few companies proposing to carry compressed hydrogen gas by ship. This would allow them to avoid the cost and complexity of liquefaction but would expose them to the same problems of lower volumetric energy density, only more so. Provaris Energy has designed a ship carrying hydrogen gas at 250 bar. But this translates to just 25 kilograms of hydrogen per cubic meter – just over a third of the very poor volumetric density of liquid hydrogen. Scaled up to the size of a Q-Max, their ship would carry around one seventh of the energy. Seven ships to do the work of one, you can imagine what that does to costs.

There may be some niche applications for shipping gaseous hydrogen, for instance moving stranded supplies between islands, but it is not going to happen in more than homeopathic quantities.

The exotics

There are other ways of transporting hydrogen beyond liquid and gas. We’ll get on to derivatives of hydrogen in a moment, but first I want to deal with the exotics – liquid organic hydrogen carriers (LOHCs) and metal hydrides. Here the goal is to load hydrogen into a chemical or metal carrier, which allows it to be transported at ambient temperatures and pressures. On arrival the hydrogen is released and the carrier returned to the point of origin.

One promising LOHC is benzyl toluene, being marketed as a solution for hydrogen shipping by a company called Hydrogenious. But again it has a volumetric density problem. One cubic meter of benzyl toluene can only be loaded with 54 kilograms of hydrogen – which means four times as many trips for each energy cargo as you would have with LNG. In addition, loading hydrogen into the organic solvent is an exothermic process, generating heat where you don’t need it, and then you need to add energy at 300C at the arrival location to extract it – using up around 30% of the delivered energy.

That’s not to say LOHCs are not interesting: they could perhaps find a role in long-duration stationary storage – not everywhere has the salt caverns or depleted gas fields required to store gaseous hydrogen, but any tanker farm would be able to handle benzyl toluene and there may be options to store and reapply the process heat between cycles. There may even be a modest import market for LOHCs, to replenish long-duration storage tanks.

Metal hydrides offer the hope of transporting up to twice as much fuel per cubic meter as liquid hydrogen – but each family of hydrides studied so far has shown disadvantages: cost, gravimetric density, time to charge, absorptive capacity, heat required to release the hydrogen and so on. It would be a brave investor who thought we were going to move hydrogen at scale this way, when 50 years of research has not yielded as single commercial application.

First derivatives

Next up, hydrogen derivatives – e-methane, e-methanol. These are certainly easier to transport – drop-in replacements for their fossil equivalents. Their problem is high production cost. For each of them you need a source of clean hydrogen – whether blue, green, pink or red (from nuclear power, whichever color code you use) or whatever – plus a source of carbon nearby, and then you need to combine them into molecules of varying degrees of complexity.

The cheapest source of carbon would be captured from the combustion of fossil fuels – but that would make no sense as it would not be compatible with net zero. The only thing that could possibly make sense would be to use direct air capture (DAC) or secure carbon from a bio-based source, so that when it is burned it just returns to the atmosphere.

A bit of systems thinking, however, shows that even this makes no sense. Take e-methane. By the time you have gone to the cost of securing your carbon, why not just sequester it, instead of incurring further costs in producing hydrogen and combining them into your derivative. You could then just deliver plain old fossil gas to the importing country – along with a carbon credit if needed. That would be identical from a climate perspective and vastly cheaper.

Methanol can and must be made in future using clean hydrogen. Some of it will be made where hydrogen is cheap and exported, but only for use cases where it will be consumed as methanol. In 2022, global production of methanol was 110 million tonnes – but adjusting for molar weights, that is equivalent to just 14 million tonnes of hydrogen. Should demand double and a third of that get traded internationally, only a 9 million-tonne import market by hydrogen mass would be created. That barely scratches the surface of the Hydrogen Council’s 400 million tonnes.

E-methanol also represents a potential pathway to decarbonize shipping – but ammonia and waste-based biofuels both look like being cheaper. Even using nuclear power for the world’s largest ships would most likely be cheaper than e-methanol. Global shipping fuel demand today is around 300 million tonnes per year; let’s suppose, optimistically, that demand increases by 50% by 2050, that 20% is replaced by methanol, and a third of that methanol is traded internationally. Once you adjust for the molar mass and energy content of methanol, that would only create annual demand for another 8 million tonnes of hydrogen imports.

e-Fuels

Some continue to promote e-fuels as the solution for land transportation, particularly in Germany and Japan. They point to the fact such fuels require no changes in consumer behavior, highlight the millions of jobs that depend on the internal combustion engine and claim that scrapping 1.4 billion internal combustion vehicles on the world’s roads would be unaffordable.

Their arguments have no merit. First, those 1.4 billion vehicles will be scrapped anyway before whichever year countries select for net zero. In most cases, electric vehicles are already competitive on a total-cost-of-ownership basis with petrol and diesel. E-fuels, by contrast, will still be three to five times as expensive in 2050, driven by their production complexity and the efficiency losses at each production stage. Yes, Porsche is building a pilot project in Chile to produce e-fuels, but theirs is not exactly a cost-conscious customer base.

The fact is that those jobs associated with internal combustion engine manufacturing will be disappearing anyway, the only question is whether they are lost to other technologies or to China. As for behavioral change, most EV users like the fact that they can charge anywhere, rather than having to visit a gas station every week.

Flights of fancy

Time for a deep dive into hydrogen’s potential use in aviation. Airbus has said that it “considers hydrogen to be an important technology pathway to achieve our ambition of bringing a zero-emission commercial aircraft to market by 2035,” and this month, Rolls-Royce and EasyJet made the news by testing a turboprop engine on pure hydrogen.

It turns out that running an aircraft engine on hydrogen is not the difficult bit – the Soviet Union did it back in 1988, not on a test bench but in the air. The real problems are caused, once again, by the physics of hydrogen.

With just 25% of the energy density of kerosene, replacing the maximum take-off fuel load for a long-haul aircraft would require more space than the entire swept volume of its fuselage – a non-starter. For short-haul flights, the focus of Easyjet’s interest, the fuel tank would take up around a third of the fuselage. That means ticket prices 50% higher than now, even before paying for the higher costs of the plane, the cost of the liquid hydrogen, and cost of its ground handling equipment. In total, expect a doubling or tripling of prices.

The real show-stopper, however, is getting the fuel to the airport. Liquid hydrogen transfer lines exist, but there is no way to keep miles of pipeline at -253C and handle the safety issues of any potential leaks. That leaves road tankers or gas pipelines.

Let’s do a thought experiment: try to replace all 20,000 tonnes of jet fuel delivered daily to Heathrow airport with 7,200 tonnes of liquid hydrogen. By tanker truck, that would mean 2,300 daily movements of liquid hydrogen in West London. The safety and traffic implications don’t bear thinking about. Now the only option is to bring the hydrogen in by gas pipeline, and liquefy it on site. But that would require 2.7GW of electrical power, according to engineer and Oxford University ammonia expert Dr. Mike Mason – approximately the output of a new nuclear power station the size of Hinkley C, plus a lot of pylons. And then you need to dump enough heat to raise the temperature of the Thames by 18 degrees C.

The bottom line is that liquid hydrogen could perhaps end up powering a few executive jets – startup ZeroAvia certainly hopes so – but not aviation as we know it. The only substantial role for hydrogen in aviation would be through the production of e-fuels. These are certainly technically feasible – UK company Zero Petroleum has already made some – but they look like being at least twice as expensive as sustainable aviation fuels (SAF) based on agricultural or forestry waste.

If potential volumes of SAF are limited by feedstock availability, then there is a market opportunity for hydrogen in aviation fuels, if not, there isn’t. Global aviation fuel demand was around 300 million tonnes in 2019, which translates to 46 million tonnes on a hydrogen mass basis. If demand grows by 50%, 25% is met by e-jetfuel and one third of that is shipped internationally, that only generates 6 million tonnes of traded hydrogen.

Moan, moan, ammonia

That brings us, finally, to ammonia – the last option for those hoping to develop substantial long-distance hydrogen imports.

Around 190 million tonnes of ammonia are produced each year, mainly for fertilizer and as a chemical feedstock, almost all of it from fossil feedstock. Around 10 percent of current production is already traded internationally but this only comes to around three million tonnes by hydrogen mass.

Switching to clean ammonia for fertilizer production will without doubt drive a big increase in traded hydrogen. Where there are pipelines, hydrogen can be made where renewable power is cheap and imported in place of natural gas and used to make ammonia at the destination. Where there are no pipelines, green ammonia or finished fertilizer will be produced and shipped instead.

Supposing the fertilizer market grows by half by 2050, all of it goes low-carbon and a third of it ends up being shipped internationally, that would increase ammonia trading from 18 to 95 million tonnes per year – a lot of ammonia. This will be a relief for those investing in ammonia projects in Chile, Canada, Namibia and South Africa: their output may not find much use in the energy sector, but at least they should have access to a very substantial market. It is, however, only 17 million tonnes on a hydrogen mass basis.

Back to shipping fuels. Since ammonia will be cheaper than methanol, as discussed, let’s be optimistic and say half of the volumes described above are replaced with ammonia, and a third of it is traded internationally. That would drive an additional 25 million tonnes of demand by hydrogen mass.

Japan’s big bet

Japan is betting that imported ammonia will be used to generate power. Its national decarbonization plan is based on retaining its coal-fired power stations, but fueling them with increasing proportions of ammonia – first 20%, then 50%, then 100% by 2050. So confident is it – and so keen to keep selling its technology internationally – that it is encouraging Vietnam and other South-East Asian countries to keep building coal-fired power stations. Will the bet pay off?

Let’s look first at ammonia made from green hydrogen. That means generating wind and solar power; using it to produce hydrogen (80% efficiency); making ammonia via the Haber-Bosch process (70% efficiency); liquefying it (90% efficiency); shipping it (90% efficiency); and burning it to generate power (45% efficiency). Your end-to-end efficiency will be an astonishingly poor 20%. Although it might be possible to improve the efficiency of each of stage, the tyranny of multiple process steps means your end-to-end efficiency is hard to budge.

What 20% end-to-end efficiency means is that the resulting power will cost five times as much as the original power – and that is before accounting for capital invested in all those process stages and maintenance. In addition, combustion of ammonia produces nitrous oxides – hazardous to health and powerful greenhouse gases in their own right.

Now, ammonia from blue hydrogen. You eliminate the electrolysis stage, so your end-to-end efficiency is a little higher at 26%, but you have the extra cost of carbon capture and sequestration, so the resulting power cost is going to be about the same. The real question, however, is why bother? Why not just ship the natural gas to Japan instead of ammonia – LNG has 1.7 times the volumetric energy density of ammonia, so you need fewer cargoes. Then you capture the CO2 at the other end, and either sequester or send it back to the point of origin on the same ships. You have the same climate impact, approximately the same cost of carbon capture and sequestration, but significantly greater efficiency and lower shipping costs.

The bottom line for ammonia as a fuel for power generation, whether co-fired or pure, is that no economy can be internationally competitive based on the resulting power prices. My estimates are in line with the more detailed modelling work undertaken by BloombergNEF: BloombergNEF found that 100% ammonia-fired power in Japan would cost around $260 per megawatt-hour in 2030 and $200 by 2050 – around double the cost of renewable energy.

The fact that Japan could generate large amounts of renewable energy – in particular, offshore wind – at much lower cost points to the role that clean ammonia could in fact play in the country’s power system: providing back-up. Bill Gates likes to quote Vaclav Smil on the three-day cyclones that hit Tokyo almost every year – which would shut down renewable generation and leave it short of 22GW of power. He laughs at the idea that batteries could fill the resulting gap, and he is correct to do so. However, the gap is only 1,600 GWh, which could be generated from a million cubic meters of ammonia – an amount that could be brought in on just four Q-Max-sized carriers.

So, while basing Japan’s economy on electricity generated from imported ammonia is an economic non-starter, storing a few million tonnes of ammonia and using it for long-duration storage looks a lot more realistic.

Conclusions and implications

This has been a long journey and we have covered a lot of ground. I want to leave you with a few conclusions by way of summary.

The only way to move hydrogen economically is as a gas, by pipeline. Forget liquid hydrogen: it will struggle to find any role in the future energy or transport systems because of its poor volumetric energy density and difficulties with handling. It will have no role at all as a traded commodity.

Ammonia will be traded and transported, primarily for use in fertilizer production, plus as a shipping fuel. It will not be imported to power bulk power generation, but will be imported and stored to deliver long-duration storage. Some LOHC might also be imported, but only where it is stored for resilience purposes.

Clean methanol will be made near to sources of cheap clean hydrogen and some of it will be shipped around the world for use as a chemical feedstock. E-fuels – whether methanol, petrol, diesel or kerosene equivalents – will not be shipped around the world in meaningful volumes because their cost will severely limit their uptake, with the possible exception of aviation.

Totting up the various future hydrogen trade flows covered here, it is clear that the Hydrogen Council/McKinsey figures of 660 million tonnes of clean hydrogen production and 400 million tonnes of long-distance transportation are out by a factor of at least three. In addition, given that China and India have only pledged net zero by 2060 and 2070 respectively, such flows that do materialize will take decades beyond 2050.

The implications reach far beyond the question of international trade in hydrogen and its derivatives. The prohibitive cost of long-distance imports means that energy-intensive industries will inevitably migrate to regions with cheap clean energy. It is inconceivable for any country to import iron ore from Australia or Brazil, hydrogen from Australia, the Gulf, Canada or Africa, and make steel at a globally competitive cost. Magical thinking will be no defense against de-industrialization.

Finally, it is worth noting that none of this calls into question the fact that clean hydrogen will be required to decarbonize certain sectors, which will eventually create more than 100 million tonnes per year of demand. Just as railway mania left the world with railways, electricity mania left the world with power networks, and the dot-com bubble left the world with broadband fiber, so hydrogen mania will leave the world with a lot of clean hydrogen.

The worry is that, along the way, we are going to waste huge amounts of money on the wrong use cases for hydrogen and the wrong infrastructure in the wrong places. Worse than wasting money, we will also be wasting time – and that is the one thing we don’t have. Let’s be smart.

Selah.

Michael Liebreich is the founder and senior contributor to BloombergNEF. He is also the CEO and chair of Liebreich Associates, founding managing partner of EcoPragma Capital and an advisor to the U.K. Board of Trade.

Source: BNEF

 

The concentrated solar power phoenix

A few years ago, concentrated solar power (CSP) looked as if it was going to be an immensely valuable resource to increase the share of renewables in the grid.   

CSP used mirrors to concentrate the rays of the sun on a central "receiver" which got so hot it melted sodium salts.  These molten salts (at ±600 C) could be used immediately to boil water to create steam and drive conventional turbines to generate electricity, or they could be stored to be used later, typically overnight.  The molten salts in their special reservoirs lost heat very slowly, so could be stored for days or even weeks.   

The cost of the CSP power station lay mostly in the mirror array and the receiver, not the storage, so adding storage was much cheaper than adding storage via batteries to solar panels is.  In principle, CSP could provide baseload power more cheaply than coal and much more cheaply than nuclear.   The only problem was ..... the storage tanks kept on cracking, leaking the molten salts and reducing or stopping output.  And so, the CSP dream ended.   

Except it didn't.

An Australian company, Vast Solar, developed storage tanks which were flexible enough not to crack, with a modular system which allowed bigger CSP plants.  I talked about it before, here.

Well, Vast Solar is going from strength to strength.  It's being listed on the NYSE, and has expanded its development pipeline to 3700 MW, with 230 MW of projects under development.

Now that the technology works efficiently, the potential to scale is dramatic. The total addressable market for CSP by 2050 will be between 700 and 1,800 gigawatts (GW), with a revenue potential of over $3.5 trillion, according to a top tier international management consulting firm. The International Energy Agency (IEA) forecasts deployment of up to 430 GW of new CSP capacity globally by 2050 for on-grid applications alone.

That leaves room for many players to succeed but Vast Solar is a first mover [and owns the copyright to the flexible tanks] – and [is] already getting a piece of the pie. The company has 230 megawatts of projects under development, with a total pipeline of 3.7 GW, as of February 2023.

Large governments around the world are firmly backing the business. Up to A$ 215 million of funding has been committed by the Australian and German governments.

Importantly, the technology is tried and true, with CSP v3.0 already piloted for over five years and de-risked through a grid-synchronized demonstration plant that’s operated for nearly three years. The modular tower modality and sodium-based heat transfer technology provide a design that increases reliability and efficiency, while reducing complexity, cost and construction time.

To accelerate deployments in the US, the Inflation Reduction Act (IRA) is expected to materially improve project economics through the 30+% investment tax credit. The partnership between NETC and Vast Solar represents an attractive entry point for some of the most topical energy transition macro themes: dispatchable power, storage, process heat and green fuels.

Traditional storage solutions come with many compromises such as cost, safety and supply chain issues. CSP offers a variety of key features, including carbon-free, dispatchable power and heat, lower cost technology for sun-belt countries, highly efficient systems with minimal losses, integrated energy storage with thermal batteries that charge themselves with daylight, and a low-risk supply chain consisting primarily of glass and steel.

CSP solves two problems that wind and solar photovoltaics (PV) cannot. Wind and solar PV are intermittent generators. Adding battery storage allows wind and solar PV to be dispatched, but only with limited duration, at a high cost and with significant trade-offs. CSP provides efficient long-duration storage which makes it comparable to traditional fossil generation.

Decarbonizing manufacturing is challenging because many industrial processes require heat that can only be efficiently generated by burning fossil fuels. CSP can generate process heat equivalent to burning fossil fuels, allowing manufacturers to decarbonize.

Vast’s Modular Tower is a new and innovative approach to CSP that seeks to address the challenges facing conventional CSP. The Modular Tower utilizes molten sodium as its heat transfer fluid, which enables a modular tower design that unlocks benefits that collectively drive down costs and de-risk the operation.

These provide a variety of advantages, including reduced construction time, locational flexibility, lower operational risk through better thermal process control, higher operating temperatures delivering improved plant economics in both salt storage and turbine efficiency, and the ability to alter dispatch to meet changes in grid circumstances.

Additionally, modular towers offer a safer and cheaper way to conduct maintenance on a smaller tower and receiver, increasing the ability to meet customer requirements for both power and heat.

Turning to deployment goals, the company has a focus on several sunny regions, including stretches of North America, Europe/Middle East, APAC, Latin America, Central and South America, and Africa.

One proof point is Vast Solar’s 50-megawatt Mount Isa solar thermal plant, located in northern Queensland state, which is also a testament to the growing demand for renewable energy. The isolated mining community will benefit from the plant, which incorporates technology that allows heat from the sun to be stored for up to 16 hours.

[From Yahoo!Finance] 

Because CSP enables longer storage than batteries, it will play a key part in the renewable grid, and it will reduce the need for gas peaking.   The grid of the future will have wind, solar, CSP, and other lesser sources of green electricity (micro hydro, wave power, tidal power).  The greater the variety of generation sources, the more stable the output.

In addition, Vast Solar has also signed a LOI (Letter of intent) to build a green methanol plant co-located with its CSP plant at Port Augusta in South Australia.  Green methanol (CH₃OH) is much more useful than green hydrogen, because it can be stored and transported at room temperature.  See this article and this one about green methanol.  I wrote about methanol here, and you can read other pieces I wrote here. 

Methanol is another way of storing surplus electricity indefinitely.    So both these initiatives will make it easier to get to zero carbon.

Out of thin air

From The Guardian

Researchers have created a solar-powered device that produces hydrogen fuel directly from moisture in the air.

According to its inventors, the prototype produces hydrogen with greater than 99% purity and can work in air that is as dry as 4% relative humidity. The device would allow hydrogen to be produced without carbon emissions even in regions where water on land is scarce, they say.

Hydrogen is a zero-carbon fuel that yields only water as a byproduct when used in fuel cells. However, pure hydrogen is not abundant in nature [on Earth: it is the most plentiful element in the universe] and producing it requires energy input. Large-scale production commonly involves fossil fuels that generate carbon emissions.

The study’s lead author and a senior lecturer in chemical engineering at the University of Melbourne, Dr Gang Kevin Li, said the hydrogen-producing device could be powered by solar or wind energy.

A prototype produced hydrogen for more than 12 consecutive days in a monitored trial. “[For] one of them, we left it to run by itself for eight months,” Li said.

The device is comprised of spongy material with a hygroscopic liquid – fluid that absorbs moisture from the air, similar in function to silica gel sachets. The absorbed water molecules are then split at electrodes into hydrogen and oxygen gasses, a process known as electrolysis.

“Hydrogen is the ultimate clean energy … as long as you have renewable sources of energy to electrolyse the water,” Li said.

The device is estimated to produce up to 93 litres of hydrogen a square metre an hour. “If you have 10 sq metres of this unit, you can power a whole house … to replace your consumption of natural gas at home for cooking and heating,” Li said.

The prototypes are still only small in size, and the team has plans to create 1 sq metre and 10 sq metres units in the coming year.

The researchers envisage the device could be a useful tool in regions where liquid water is not readily available for producing hydrogen. “Large parts of the world have water scarcity problems,” Li said. “When you have lots of renewable energy – wind or solar – you [often] don’t have much fresh water for this type of hydrogen production.”

Dr Kim Beasy of Swinburne University’s Victorian Hydrogen Hub, who was not involved in the research, said hydrogen fuel, while important, was not a silver bullet for reaching net zero. “We’re coming to understand that hydrogen is going to be one piece of the puzzle,” she said.

“It’s going to provide us with direction out of some pretty hard-to-mitigate industries such as transport. We have no alternative to diesel at the moment … hydrogen is a really good option.”

The required economies of scale were “probably not going to be reached with clean hydrogen straight away”, Beasy said, citing the expensive price of conventional hydrogen electrolysers. “What we really need is more government support and subsidies in bringing down the cost of getting this technology on the ground.”

The study was published in the journal Nature Communications.

This article was amended on 14 September 2022 to make clear that hydrogen produces only water as a byproduct when used in fuel cells. When burned in air it also produces nitrogen oxides.

Hydrogen is a difficult green fuel.  Its atoms are so small it escapes easily through the atomic lattices of metals, and it makes pipelines brittle.  Converting hydrogen to methane via the Sabatier process makes it much easier to transport and store.  An additional use for this technology is to produce water in deserts.  

a water risk and solar energy potential; b water risk and wind energy potential (excluding coast areas).
Source: Nature

Hydrogen efficiency will beat expectations

 From a Twitter thread by Gniewomir Flis

Hydrogen efficiency will beat expectations After spending the last six months looking at cutting edge hydrogen tech I believe that the prevailing view that hydrogen is inefficient needs an update. There’s much innovation to be excited about on the horizon.

Take this T&E [Transport & Environment] chart for instance, which assumes that electrolysis is 76% efficient, and fuel cells are only 54%, which together account for the bulk of the losses. Almost every paper out there uses similar, often worse, numbers.

Current tech is already better than that. For instance, Nel’s stack can be up to 93% efficient (3.8kWh/Nm3 H2). Those numbers are rarely achieved in practice though as the stacks are run at higher current densities (=lower efficiency, but less capex)

But efficiencies are getting better. See the performance of the Oort Energy stack. 90% efficiency at 2A/cm2. This is not some experimental stuff, it’s a full sized stack ready to be manufactured.

In addition to high efficiency, Oort can electrochemically pressurise H2 internally to 200 bar at less than half the energy cost of mechanical compression.

You may also have heard of Hysata which set a record breaking efficiency (98%), though tech is still several years away from commercialisation as it has serious degradation problems.


But more innovation is coming. From the less conventional architectures, we’ve got H2Pro which claims 95% efficiency. So, upcoming electrolysis solutions are looking pretty efficient to me, a step up from the 70-75% efficiencies assumed by many today.

On the fuel cell the innovation is just as good, if starting from a lower baseline (50%). The technology to watch for is high temperature PEM. By high temperature I'm referring to 200C, which aids in rejection of water, a rate limiting step.

Practically, this means that high temperature PEM fuel cells would enjoy a 30% increase in efficiency, i.e from 54% to 70%. Several companies working on this, like Hy-point, Advent, or Mebius. [See this article in Electrive]

Applying these innovations to the T&E chart: Hydrogen production with storage is now 82% efficient.

Round trip efficiency is now 54%, so only 1/3rd less efficient than using electricity directly. Compare with 42% T&E had assumed for… 2050!

And that’s not the end of it. In the storage part, companies like @RuxEnergy (metal organic frameworks) or @VerneH2 (cryocompression) are almost able to match the density of liquified hydrogen without 40% energy loss.Does this change the calculus for hydrogen? To a certain degree. On the road batteries have a significant first mover advantage which I think they’re likely to retain, especially since this up and coming hydrogen innovation won’t get commercialised overnight.


But hydrogen might feel a boost in heavier and infra sensitive applications. I think regional aviation will be a good case in point. Heavy trucking and construction too. Trains could be a good one.


High temperature process heat is another one which would also get a boost. Even if heating with hydrogen is 12% less efficient than with electricity, it may be simpler to repurpose gas infrastructure than it is to lay hundreds of MW of new lines. EU modelling sees a role here.


To conclude: electrolysis is becoming much more efficient than the 70% it gets quoted on. Fuel cells are also getting better. Does this mean we’re all getting FCEVs and hydrogen boilers in 2030? Probably not, but other applications may get a hydrogen boost.


To conclude: electrolysis is becoming much more efficient than the 70% it gets quoted on. Fuel cells are also getting better. Does this mean we’re all getting FCEVs and hydrogen boilers in 2030? Probably not, but other applications may get a hydrogen boost.


Perhaps the real prize here is not that FCEVs are more efficient, but that we will need much less renewable energy to introduce green hydrogen in feedstock applications.

See also his corrections in this thread

The key point is this: producing hydrogen from electrolysis is going to become much cheaper, and hydrogen fuel cells are going to get more efficient. That will mean hard-to-de-carbonise sectors like heavy-duty trucking, air transport and sea transport will be able to switch to hydrogen from fossil fuels. More efficient electrolysis will also make power-to-gas (producing green hydrogen to be later used to make electricity in the grid) will become much cheaper, allowing us to reach the holy grail of long-term storage via methane.