Hydrogen News from USA

‘Magic molecule?’ | US state trio team to bid for $1bn federal hydrogen hub funds

Arkansas, Louisiana, and Oklahoma move to set up a regional hub for full-spectrum development and production of hydrogen as fuel and manufacturing feedstock

The US states of Louisiana, Arkansas and Oklahoma have formed a partnership to set up a regional hub for development, production, and use of blue, green, and possibly pink hydrogen as both fuel and manufacturing feedstock.

“This is an extension of Louisiana’s ongoing efforts in diversifying the makeup of our energy sources and ensuring an economically and environmentally balanced approach to cleaner use of traditional fuels and transition to new potential energy sources,” said governor John Bel Edwards.

The three states intend to team and compete for $1bn or more federal funding of the $9.5bn available under the Infrastructure Investment and Jobs Act (IIJA) of 2021 for creation of four regional clean hydrogen hubs, and hydrogen-related demonstration and manufacturing activities.

In February 2022, Colorado, New Mexico, Utah, and Wyoming announced they will jointly seek an unspecified amount of federal funding for a proposed Western Inter-State Hydrogen Hub that would have facilities in all four states.

IIJA specifies that the Department of Energy (DoE) will select the hubs based on a mix of feedstock available to produce hydrogen, available end-users of hydrogen, geographic locations, and potential effects on employment, among other considerations.

DoE Secretary Jennifer Granholm will have to winnow-out at least one hub proposal from each of three clean-hydrogen production routes: carbon capture and storage (blue), renewables (green), and nuclear (pink). The deadline for solicitating proposals is 15 April.

“A hub can mean a lot of things. In this case, it represents a cluster of end-use demonstrations we could do to prove the commercial viability of hydrogen in certain types of applications,” Kenneth Wagner, Oklahoma secretary of energy and the environment, told The Oklahoman.

No specifics have been nailed down yet, but by design, we could demonstrate its commercial value across the entire value chain within our three states,” he added, noting: “We are not suggesting this is the magic molecule.”

Rather, they view hydrogen as another potentially cleaner, lower-cost alternative that could help create more stability in regional energy markets. At present, the great majority of hydrogen is made in a carbon-intensive manner for use in industrial processes.

The three states consider themselves as “perfectly situated” to demonstrate how the entire value chain of hydrogen can tackle hard-to-decarbonise sectors like industry, manufacturing, and transportation.

The partnership seeks to build upon existing advantages, such as an inland seaport system that runs from Oklahoma through Arkansas and down the Mississippi River to the Gulf of Mexico in Louisiana.

There are also existing intermodal rail, interstate highway, and pipeline infrastructure that run from Oklahoma through Arkansas to the Gulf of Mexico.

Private companies are already investing in hydrogen production in Louisiana, Oklahoma and elsewhere.

Air Products announced it will spend $4.5bn to construct a massive facility in eastern Louisiana that will produce a daily 750 million ft3 (21 million m3) of blue hydrogen and capture and store the carbon in underground salt caverns.

In Norman, south of Oklahoma City, Australian company Woodside in December 2021 announced a plan to build a facility able to produce up to 90 tons/d of liquid green hydrogen for the heavy transport sector starting in 2025 with the location capable of doubling output later this decade.

Among the biggest renewable hydrogen projects nationwide include start-up Green Hydrogen International’s 60GW H2 facility in South Texas, to be powered by wind and solar. Southern California Gas Company’s Angeles Link calls for employing 25-35GW of curtailed and new wind and solar power, plus 2GW of energy storage, to power 10-20GW of electrolysers to produce H2.


World’s largest green hydrogen project unveiled in Texas, with plan to produce clean rocket fuel for Elon Musk

The 60GW Hydrogen City project, announced by local start-up Green Hydrogen International, will be powered by wind and solar, with an on-site salt cavern for H2 storage

US start-up Green Hydrogen International (GHI) has announced a 60GW renewable H2 project in a sparsely populated area of South Texas, to be powered by wind and solar, with its own salt cavern for storage and a plan to produce clean rocket fuel for Elon Musk’s SpaceX.

The project in Duval County — a sparsely populated Democratic stronghold about 145km (90 miles) west of Corpus Christi — would produce more than 2.5 million tonnes of green hydrogen a year upon completion, equivalent to roughly 3.5% of global grey hydrogen production today.

It will be centred around a hydrogen storage facility in the Piedras Pintas Salt Dome, with pipelines to the port cities of Corpus Christi and Brownsville on the Mexico border, where SpaceX’s Starbase is located.

The company is looking at combining hydrogen with CO2 at the Port of Brownsville to create a green methane rocket fuel for launch operations in South Texas,” GHI said in a statement.

SpaceX is currently developing a new type of rocket engine called SpaceX Raptor that would use cyrogenic liquid methane and liquid oxygen, rather than the kerosene-based fuel the company has used to date.

The first 2GW phase of Hydrogen City is due to begin operations in 2026, with two storage caverns in the salt dome.

“Access to salt storage is critical to the scaling-up of green hydrogen production as it allows for maximum utilization of electrolysers and serves as a buffer between variable wind and solar production and final delivery of green hydrogen to customers,” said GHI.

The Texas-based company — founded in 2019 by experienced renewables developer Brian Maxwell — says it could create more than 50 hydrogen storage caverns in the salt dome, “providing up to 6TWh of energy storage and turning the dome into a major green hydrogen storage hub, similar to the role Henry Hub plays in the natural gas market”.

GHI says it is exploring several possible end-uses for its hydrogen, including: sustainable rocket fuel; clean aviation fuel; green ammonia for fertiliser production, or export to Asia; or as a substitute for natural gas in power plants.

“We see Hydrogen City becoming one of the largest H2 production centers in the world, supplying many different customers with 100% clean H2 fuel,” said Maxwell.

GHI board member Andy Steinhubl added: “Hydrogen City is a project perfectly positioned near low-cost renewable resources, plenty of available land, salt domes, and proximity to the large energy port of Corpus Christi. It will be a world cost leader and position GHI to take advantage of the growing demand for green hydrogen.”

While Hydrogen City would be mainly powered by local wind and solar farms, GHI adds that it plans to draw “additional renewable energy… from the [local] ERCOT grid during periods of low prices.”

The largest single-site green hydrogen project announced until now has been the Western Green Energy Hub in Western Australia, which would be powered by 50GW of wind and solar, although it is not clear what size electrolysers would be used. A planned 30GW facility in Kazakhstan, powered by 45GW of wind and solar has also been unveiled.

There is also a project called HyDeal Ambition that adds up to 67GW at multiple sites across Spain, France and Germany.


The case for hydrogen trucks | Grid limitations will make long-distance battery-electric haulage ‘near impossible’: Hyzon Motors CEO

Those advocating for an all-electric future for road transport do not understand how difficult and expensive that would be in practice, Craig Knight tells Recharge

For a hydrogen-fuel advocate, Craig Knight, the CEO and co-founder of US hydrogen truck and bus maker Hyzon Motors, is surprisingly cynical about the zero-emissions gas.

He does not see a bright future for hydrogen cars, admits that green H2 can be considered an inefficient use of renewable electricity, believes that trucking hydrogen to filling stations is a “bad” and expensive way to move the gas around, and is also not a fan of blue H2.

Yet at the same time, he strongly believes that hydrogen is the only viable carbon-free solution to long-distance trucking.

“Doing a few battery electric trucks is easy; doing hundreds is near impossible,” Knight tells Recharge. “Doing a few fuel-cell trucks is a pain in the butt; doing hundreds is a walk in the park.”

The Australian says that those advocating against long-distance fuel-cell trucks and in favour of battery-electric versions, such as the Fraunhofer Institute for Systems and Innovation Research in Germany, are missing the following key points:

1) That grids will not be able to cope with the sheer amount of electricity required to fast-charge multiple battery trucks at the same time;

2) That longer charging times for battery trucks means that an all-electric system would require eight times as many chargepoints as a fuel-cell lorry network;

3) That long-range truck batteries would be exceedingly heavy, reducing the efficiency and adding to the cost of transporting goods over long distances;

4) That it would be easier and cheaper to increase the range of a fuel-cell truck, compared to a battery one;

5) That batteries require more hard-to-obtain raw materials than fuel cells;

6) That low-cost green hydrogen can be produced locally from waste, or made from electricity when there is excess electricity, taking pressure off the power grid and removing the need to transport the H2 across long distances.

Let’s look at each of his points in turn, as well as the arguments against using hydrogen as a road fuel:

1) Grid limitations

One of the arguments in favour of long-distance electric trucks is that a new megawatt-scale EV charging standard of up to 2MW is now under development, which would theoretically enable truck drivers to add 400km of range in about 20 minutes — comparable to the 10-15 minutes it would take to fill up a hydrogen tank with the same range.

But Knight points out that such chargers would require expensive grid upgrades.

“When you invest in that type of charger, you will need to upgrade the grid supply, [I can] absolutely guarantee it,” he tells Recharge. “And you may need even to upgrade the regional grid transmission and supply.

“After the first five or ten [battery] trucks, I guarantee you’ll have to do that.”

Knight says that several bus operators around the world, including one in Sydney, Australia, have already run into problems with the charging of multiple battery-electric buses.

The guys in Sydney had to spend quite a bit of money [on upgrading their electricity supply] just to get the first four [battery buses] set up. They ran these first four buses for a little while and the manager of the depot got a call one day from the local substation operators. And they said, ‘I just wanted to talk to you about how much power is actually being used… how big is your depot? [The depot manager] said, ‘Oh, we’ve got about 140 buses. They said, ‘Oh right, no wonder you’re using so much power’. And the guy at the bus depot says, ‘but we’ve only got four battery buses’.

“And the electricity supplier guy goes, ‘You’re telling me, you’re using this much power charging four buses? In that case, I better just check how many you’ll be able to charge before you max out the grid’. And the bus operator said, ‘yeah, you better tell us how many, because we quite like these battery buses, we’re planning to get more’.

“He [the power supplier] said, ‘your maximum number of buses in that location here in Sydney with this grid is six buses. If you charge at a higher rate than that, we’ll simply turn you off… because you’ll pull down the [grid for the] whole inner west [area] of Sydney, it can’t sustain this amount of power.”

Knight continues: “I spoke to the CEO of that business and he said, that to them was the dawning of their realisation of where this crossover point between batteries and hydrogen really is. It’s a lot lower down the curve than people think. And I have heard very similar stories from truck and bus operators who’ve tried battery electrification.”

The Hyzon boss adds that heavy-vehicle fuel stops on the highway typically fill up dozens of diesel trucks at the same time. This is partly because “trucks travel in packs… so wherever you’ve got one truck wanting a fast charge, you’ll have a lot more”.

If the same number of battery electric trucks tried to simultaneously fast-charge at the same location, “that will suck down staggering megawatts of power from the grid”, he explains.

“You have to multiply 1-2MW per charger by how many trucks need to charge [simultaneously]. And these roadside locations can’t deliver that much power. So perhaps the upgrade to all that fast-charging infrastructure actually brings with it multi-billion-dollar electricity infrastructure upgrades that need to happen everywhere you’d want to charge [battery] trucks.”

Knight says that while China has something like 500,000 battery electric buses in operation today, fleet operators “know their limitations, they know what they’ve had to pay to upgrade the electricity grid — crazy amounts of money. They know how they’ve had to buy extra land to fit charging capabilities and all the rest of it. They know the headaches of trying to charge those things every single day”.

“I’ve spoken with the operations director of the largest electric bus fleet in China. He said to me ‘if your technology was where it is now ten years ago, I don’t think we would have battery buses’.”

Knight does concede that electric buses are more than capable of travelling over 100km a day, but he points out that the average power consumption of a city battery bus is 20kW or less, compared to 100-140kW for a Class 8 ultra-heavy truck.

“This is not an efficient way to use batteries and the electricity [that would be] used to charge them. Hydrogen fuel-cell electrification offers the potential for a more capital-efficient decarbonisation of commercial fleets in a way that can be free of obligations on the grid, or be used as a grid service. When you’ve got power you can’t use, put it in hydrogen.”

Knight adds that the cost of electricity varies according to how much renewable power is on the grid at any given time.

“Peak power prices in some jurisdictions are now five times the price of off peak power. Even if there is time to charge the battery [truck], it may or may not be when power is affordable.”

2) Recharging vs fuelling times

Knight says that when the US Clean Air Task Force investigated what would be required to decarbonise heavy road freight, it found that if hauliers went all-electric, eight times as many locations would be needed for fast-charging points than hydrogen filling pumps if the same number of trucks were fuelled by hydrogen — “simply because it takes so much longer to charge and the range is less”.

“And this was with no reference to how the power can actually be supplied to all those locations in the middle of nowhere, spread across the US. That power simply does not exist today from either a generation or transmission and delivery standpoint.”

He adds that a hydrogen filling station with two dispensers could fill 200 trucks a day, compared to one per hour at a future megawatt-scale fast-charger.

“I think we can safely say that heavy-vehicle fast-charging is generally an inefficient use of capital,” Knight explains.

“The utilisation of expensive assets is important and every business needs to optimise returns on invested capital. The closer an operator gets to 24/7 operation, the more competitive or profitable their business. Suggesting that a recharge of 45-60 minutes [from an 800MW charger] is in any way comparable to filling with fuel in 10 or 15 minutes is quite spurious, in my view. There are many scenarios where each and every minute is valuable.”

The same cannot be said for fuel-cell passenger cars, he adds.

“Frankly, a Toyota Mirai that someone drives 30-40 minutes in the morning and 30-40 minutes in the evening, I don’t think it’s a sweet spot for hydrogen. The heavier [the vehicle] and the higher utilisation [ie, the number of hours per day the vehicle is in use], the much more likely it will be a hydrogen use case.

“Your average commercial truck is doing two driver shifts a day, is used for 16- 20 hours a day. It’s a very different proposition and it has a very different power and energy requirement overall [than a passenger car].”

3) and 4) Range and weight

It is an immutable fact, says Knight, that “you can’t separate power from energy in batteries”.

“And the fact that you need to continue adding batteries to either increase range or carrying capacity will be self-defeating at some point [due to the additional weight].”

By contrast, to increase the range of a fuel-cell truck, you simply add much lighter hydrogen tanks.

“Any time you make a vehicle lighter, you need less energy to propel it around. So that vehicle is more efficient for every single mile you drive. So it’s interesting that those criticising round-trip efficiency of [renewable] hydrogen don’t bother to mention the inefficiency of carting [around] extra tonnes of batteries.

“So every fuel-cell truck that can either run more efficiently or carry more payload than the equivalent battery truck is delivering a real-world benefit in commercial transport, which as we all know is very competitive world.”

5) No raw material constraints

Knight believes that the demand for certain raw materials used in batteries, such as lithium, cobalt and nickel, will be so high that in the future it will be difficult to source them at an affordable price.

“With the increasing scarcity of lithium and other battery-chemistry metals, batteries will not continue declining in price. And in fact, we’re starting to see the reversal of some of the longer-term trends already based on scarcity of supply.”

In fact, Norwegian analyst Rystad Energy stated that lithium prices were 118% higher than at the end of September 2021.

“On the other hand, hydrogen equipment and fuel cells themselves are just starting a cost-down trajectory as production is scaled,” Knight says. “Being less dependent on the exotic metals, and with very high levels of reusability and recyclability, we think fuel cells offer a compelling set of economics over the longer term.

“In fact, we argue that the increasing adoption of battery electric heavy vehicles inevitably would suffer from an increasing marginal cost of adoption. Think about that. As you do more, it gets less economic because you have the scarcity challenge around batteries.”

By contrast, he says, there are no raw material constraints on fuel cells — the equipment that converts hydrogen into useable electricity. While PEM [proton exchange membrane] fuel cells — which benefit from a higher power density and lower weight than alkaline models — use platinum as a catalyst, there will be no shortages of this expensive metal, Knight argues.

“Since we don’t react the platinum in a way that makes it hard to recover or reuse, we are very happy to take back every single fuel cell at end of life from every single vehicle. Why don’t you ask all of the suppliers of BEVs if they will take back every dead battery?” he asks, adding that every catalytic converter in petrol and diesel vehicles also contains platinum that can be easily recycled.

“I don’t believe that the world will run out of platinum in anywhere near the same rate as it will be very challenged on some of the battery chemistry raw materials.”

A report last week by French investment bank Natixis found that “there is an abundance of metal minerals in the earth’s crust which will be more than enough to satisfy future [energy transition] demand… Nevertheless, this future mined metal won’t come cheap, resources are going to get more and more complicated to exploit because of lower ore grades, depth, and tighter regulations”.

6) Local production of hydrogen, and the arguments against H2

There are several well-known arguments against using hydrogen as a road-transport fuel, including:

  • The round-trip efficiency of using renewable energy to power a fuel-cell vehicle is just 30%. In other words, for every 100kW of power, only 30kW is actually used on the road — when taking into account the electrolysis process, hydrogen storage and transport, conversion back to electricity via a fuel cell and other energy losses. By contrast, the round-trip efficiency of a battery vehicle powered by renewable energy is 77%.
  • Renewable energy would be used more efficiently via the electricity grid, and the world needs as much green power as it can get its hands on to decarbonise the grid.
  • More than 95% of the hydrogen being produced today is derived from unabated fossil fuels, so H2 vehicles cannot be considered zero emissions. What little renewable hydrogen exists today is very expensive.
  • The fossil-fuel industry is pushing to produce large amounts of blue hydrogen from fossil gas with carbon capture and storage. This would still result in large amounts of CO2 emissions, as not all of it can be captured, and would continue our reliance on methane — a very powerful greenhouse gas that often leaks.
  • Hydrogen filling stations require H2 to be trucked in on diesel-powered tankers — an expensive and highly polluting method of transporting a gas.
  • Existing hydrogen filling pumps in places like California are notoriously unreliable, often breaking down or running out of gas, with ice-cold pump nozzles frequently freezing solid to cars.

Knight does not dispute any of these points, but he believes solutions exist to many of them.

“Hydrogen is everywhere — it’s literally the most abundant element,” he says. “To suggest it’s exotic or expensive is to ignore the fact it’s all around us all the time — we just haven’t been taking advantage of it.”

Potential H2 resources, which Knight refers to as “hydrogen reserves”, include agricultural and forestry waste, municipal solid waste and landfill gas.

“People will wake up and smell the roses that we are surrounded by hydrogen. It’s just that nobody viewed the landfill dump down the road as a hydrogen reserve.”

Multiple waste-to-hydrogen companies have told Recharge in recent years that their H2 will be cheaper to produce than renewable hydrogen from electrolysers.

“Hyzon supports local hydrogen production from locally available resources. We are pursuing many partnerships on hydrogen hub models, and these resources vary from sun, wind, landfill gas to municipal solid waste and agricultural waste. We are not proponents of large centralised production on hydrogen,” Knight explains, adding that trucking hydrogen to filling stations is “a bad way” to move it around — and very expensive.

“There’s two kinds of customers that we have in the near term. One type of customer is actively pursuing green hydrogen production or supply through a partnership. And the other type of customer, which we mostly have in places like Europe and China, say, ‘We know there’s a hydrogen station down [the road], we’re willing to use it. The hydrogen coming out of it’s not yet green, but we know it will go green one day. We want to convert to hydrogen because we need to know what this journey looks like in our fleet operation’.”

As for the existing unstable hydrogen filling pumps, Knight says: “The refilling stations on the streets in California are frankly not a commercial proposition. They are striving to make it viable over time, but they’re a showcase. They’re not designed to be particularly robust or very viable, in our view.

“On the other hand, robustly designed high-capacity heavy-vehicle stations with in-built redundancy of key elements are entirely more reliable and dependable.”

And while Knight agrees that green H2 can be considered an inefficient use of electricity, he states that it is “an effective and stable means of storing energy”, particularly if excess electricity were to be diverted to electrolysers.

However, the problem with this argument is that if electrolysers are only used occasionally, the levelised cost of the green hydrogen they produce would be very high, due to the high capital expenditure.

And while Knight that clean hydrogen is expensive today, he believes costs will come down with economies of scale.

“What’s been the scale effect on batteries? What’s been the scale effect on solar power?” he asks, pointing to the massive cost reductions seen in recent years.

“We will see an experience curve drive costs down significantly… there’s been an increasing cadence of investors, governments, energy players announcing green hydrogen production plants. It is now massive.

“So in our view… costs will fall significantly through all of the hydrogen production means.”

Knight concludes: “Given the multiplier effect that each piece of hydrogen infrastructure has and the improving marginal economics from increasing adoption of fuel-cell electric trucks, we emphasise our view that fuel-cell trucks are future proof.”


Russia’s war pushes blue and grey hydrogen costs way above those of green H2: Rystad

Cost of fossil-based H2 surged by over 70% since Ukraine invasion began, turbocharging the green H2 sector, analyst say

Russia’s invasion of Ukraine has pushed the cost of hydrogen produced from fossil gas way beyond that of H2 made from renewable power, Rystad Energy said.

As the cost of grey hydrogen (made from unabated fossil gas) and blue hydrogen (made from gas linked to carbon capture and storage) surge in line with rising fossil fuel prices, the feasibility of green hydrogen (produced from renewables via electrolysis) as an affordable and secure source of renewable energy in Europe is growing, the research company said.

Green hydrogen production was already set to take off this year globally and pass the 1GW milestone, but the war against Ukraine has turbocharged the sector, Rystad said, as the costs of blue and grey H2 have surged by over 70% since the start of the invasion, rising from about $8 per kilogramme to $12-$14/kg in a matter of days.

That compares to green hydrogen production costs of $4/kg (particularly on the Iberian Peninsula), according to Rystad.

The analysts’ research showed an increasing price gap between renewable and fossil-based hydrogen.

BloombergNEF earlier this month had already pointed out the Ukraine war had pushed up natural gas prices to the point where green hydrogen is now cheaper than highly polluting grey H2 in Europe, the Middle East and Africa (EMEA) and China, but the difference the price difference then still was much more moderate.

Rystad’s analysts also stress EU plans for a €300m ($330m) funding package for hydrogen as well as the Hydrogen Accelerator Initiative from the REPowerEU plan by the European Commission to weave the bloc off its dependence on Russian energy imports.

“While industry and governments are heading in the right direction, their challenge is to lower the risks for green hydrogen investors and create incentives necessary to scale up quickly both the demand and supply,” said Minh Khoi Le, head of hydrogen research with Rystad Energy.

“Fundamentally, a world where green hydrogen fulfils the role currently played by oil, gas and coal will look very different.”

The decade ahead is a make or break one for the green hydrogen sector, Rystad said, adding that if production can be increased as planned to more than 10 million tonnes globally by 2030 and costs cut to $1.5/kg or less, then the industry will become a permanent fixture of the global energy mix.


‘More than 85% of export-oriented low-carbon hydrogen projects plan to ship ammonia, not H2’

Green NH3 is emerging as the hydrogen carrier of choice, but it’s not without its challenges, writes Noel Tomnay, global head of hydrogen consulting at energy analyst Wood Mackenzie

Ammonia, as a carrier of choice, dominates the current wave of hydrogen export projects.

Wood Mackenzie’s Hydrogen Project Tracker, which follows the progress of announced global hydrogen supply projects, shows most of the 100-plus low-carbon hydrogen supply projects announced to date in the Middle East, Australia, Latin America and Africa to be targeting exports.

More than 85% of the proposed capacity integrates ammonia and hydrogen to some degree, with ammonia intended for export markets and the remainder, hydrogen, largely aimed at domestic markets.

Ammonia is currently preferred for hydrogen exports for three reasons: its energy density; its proven synthesis technology and existing supply chains; and its potential to drive decarbonisation in its own right.

Ammonia’s energy density allows for efficient transportation of hydrogen

Arguably, the biggest technical challenge to global trade in hydrogen is its sheer volume at normal temperatures and pressures. This can be overcome by compressing the hydrogen (typically above 200 bar) and transporting it through pipelines or in tanks, by ship. Alternatively, hydrogen can be liquefied by reducing the temperature to -253°C, shrinking it to 1/800th of its volume under normal conditions.

Using hydrogen carriers such as ammonia (NH3) in liquid form at relatively low pressures has the advantage of an energy density three times that of compressed hydrogen and 1.5 times that of liquefied hydrogen. Using ammonia to export hydrogen long distances, therefore, requires far fewer ships to transport the same amount of energy.

Ammonia offers proven synthesis technology and existing supply chains

The synthesis, storage and shipping of ammonia is a well-established industry. The existing market for ammonia is around 180 million tonnes per annum (Mtpa), mostly integrated with the production of derivatives, such as urea, or fertilisers such as ammonium nitrate. The seaborne trade in ammonia is currently around 20 Mtpa and a world-scale ammonia plant is around 2 Mtpa.

Ships for compressed hydrogen, in contrast, have yet to reach commercialisation, though small volumes of compressed hydrogen are moved around via trailer-cylinders.

The largest liquid hydrogen plants proposed are in the range of 15-30,000 tpa and the only liquid hydrogen ship in construction — a proof-of-concept vessel by Kawasaki Heavy Industries — has a storage capacity of around 100 tonnes. Liquid organic hydrogen carriers (LOHC), such as toluene/methylcyclohexane systems for hydrogenation/dehydrogenation processes, have also been piloted, but the technology is less advanced still.

Methanol is another potential hydrogen derivative that can be used as a carrier, as well as a clean fuel. However, because of its carbon content, there are some emissions associated with the latter.

Hydrogen carrier technology of all kinds will continue to evolve, but the supply chain for ammonia at scale already exists.

Ammonia adoption has potential to drive decarbonisation in its own right

Low-carbon ammonia is also being recognised as a potential fuel for decarbonisation in its own right. It can replace grey ammonia or other fossil fuels in existing sectors and offers potential growth in new sectors, too.

Nuclear-averse nations, such as Japan and Germany, are particularly keen on using ammonia in power generation, while South Korea has announced plans to blend ammonia into its thermal plants, substituting 20% of its coal use. In the heating sector, ammonia’s role is also growing, including as a clean heat exchanger in heat pumps.

Ammonia may also play a role in transport. This is particularly true in the marine bunkering sector, with engine manufacturers developing internal combustion engines for ships to run on dual fuel, including ammonia, to meet International Maritime Organization decarbonisation targets.

There are also claims that ammonia fuel cells using solid oxide electrolysers at high temperatures can perform similarly to hydrogen.

And with hydrogen storage sites scarce, ammonia may emerge as a commercial medium for energy storage.

Will ammonia be adopted as the primary hydrogen carrier for trade?

Ammonia is not without its challenges. Its energy density may be higher than that of liquid hydrogen, but it is a fraction of liquefied natural gas (LNG) and gasoline, so its production and transport are expensive. Treated as a toxic chemical, its production and handling in traditional sectors are regulated, and the potential for release or spillage will restrict demand in emerging end-uses.

While ammonia is a potential carrier of hydrogen that can be unlocked by cracking or a reversal of the synthesis reaction, progressing this route at a large scale faces technical and commercial challenges. Ammonia is unlikely to supplant hydrogen as a fuel in all sectors, therefore other ways to commercially transport hydrogen long distances at scale will likely emerge. Consequently, ammonia as a carrier of hydrogen is unlikely to be the end game for hydrogen trade.

However, low-carbon ammonia can play a significant role in global decarbonisation, in both traditional and new ammonia markets. Existing technologies and supply chains can be easily leveraged to enable efficient transportation across long distances.

So, it’s no surprise that ammonia dominates the current wave of hydrogen export projects. But to be successful, the myriad potential suppliers will need to better understand the true scale of the future low-carbon ammonia market.


Samsung Ventures buys into waste-to-H2 start-up Raven as first US plant gathers steam

New technology investment outfit joins international investor cadre in financing pioneering technology as flagship facility heads for construction in California

New technology financier Samsung Ventures has joined an industrial cadre of international investors including oil giant Chevron that is backing renewable fuels start-up Raven SR, a pioneer in modular waste-to-green hydrogen technology, as it begins building what would be the US’ flagship plant.

The buy-in by Samsung Ventures, which adds to that of the US supermajor, Japanese trading house Itochu, hydrogen car-maker Hyzon Motors and Ascent H2 Fund, comes as Raven prepares to break ground on a landfill site in northern California for a waste-powered hydrogen production facility.

Through the deal, Samsung Ventures sister company Samsung C&T, one of the world’s largest engineering and construction contractors, will also “advance the scalability of Raven SR in Asian markets and beyond” as a strategic business partner.

“Our readily deployable breakthrough technology is attracting strong backing from around the globe by major companies that are intent on making a difference in the energy transition today,” said Matt Murdock, CEO of Raven SR.

“Samsung’s appreciation for our renewable fuels process will step up our ability to deliver to new markets and provide an excellent addition for worldwide renewable energy projects.”

Raven SR’s non-combustion steam/CO2reforming technology produces green hydrogen and high-specification Fischer-Tropsch synthetic fuels – which can be used as a substitute for conventional jet fuel – using a range of feedstocks, including municipal solid waste, methane and biomass.

Last year, Raven SR pulled in funding totalling $20m from its first tranche of investors.

Samsung Ventures’ investment is designed to expand Raven’s reach into the market in South Korea, an early mover in the hydrogen economy which recently announced plans to build H2 production plant capacity to levels by 2050 where it would become the country’s leading energy source.


Rapid action’ on hydrogen policy reform to decarbonise heavy industry by 2050: Irena

Mushrooming global demand driven by accelerated net zero targets will only be matched with supply if ‘more done especially from policy-making side’, says agency

Ramping up development of green hydrogen production for use in decarbonising heavy-emitting sectors such as steel and petrochemicals will need “rapid action” in streamlining government policy, if H2 production is to meet contribution targets aligned to the Paris Agreement, the International Renewable Energy Agency (Irena) has underlined, releasing a pair of new reports.

The agency spotlighted that hydrogen would see mushrooming demand globally as countries geared up to meet net zero targets, but that the current green H2 market was “at an infant stage” and “more needed to be done, especially from the policy makers’ side, to maximise green hydrogen’s impact in the decarbonising of the industrial sector and end-use sectors as a whole”.

“These new reports are particularly opportune because green hydrogen needs rapid policy action to ensure and maximise its contribution to the energy transition,” said Rabia Ferroukhi, director of Irena’s knowledge, policy and finance centre, launching Green hydrogen for industry: A guide to policy making and Green Hydrogen Certification Brief.

“As we know, [our] World Energy Transitions Outlook’s 1.5°C Scenario projects that hydrogen will provide around 10% of the necessary greenhouse gases reduction by 2050.”

Irena hydrogen specialist Emanuele Bianco added: “The industrial sector is already a major consumer of hydrogen, but we need to shift from fossil fuels-based to renewables-based hydrogen. This calls for urgent industrial policy support, and high priority for green hydrogen policy should be placed on the industrial sector.”

The European Commission is targeting 50% green hydrogen consumption in industry by 2030, “however, the use of green hydrogen in industry is still hampered by cost, technical barriers, lack of a market for green materials and products, lack of sufficient ambitious policies, and carbon leakage risks,” she said.

Irena concludes that green hydrogen industrial policies should start with the introduction of decarbonisation strategies and “tailored sub-sector planning”, while not losing sight of the fact that other energy transition issues, including carbon pricing, “are more urgent than measures to support green product market-creation”.


US DOE launches nuclear, hydrogen infrastructure programmes

16 February 2022

Days after it launched a USD6 billion programme to support the continued operation of existing nuclear power plants, the Department of Energy (DOE) has set in motion its programme to invest USD9.5 billion in clean hydrogen technologies which may include the use of nuclear power. Both initiatives are part of the Bipartisan Infrastructure Law.

President Biden pictured delivering remarks ahead of his signature of the Bipartisan Infrastructure Law in November 2021 (Image: Erin Scott/White House)

The law – its full title is the Infrastructure Investment and Jobs Act – sets out a USD1.2 trillion package as part of President Joe Biden’s Build Back Better agenda, including more than USD62 billion for the DOE to deliver an equitable clean energy future, including supporting the continued operation of nuclear power plants which currently provide more than half of the USA’s clean electricity.

“US nuclear power plants are essential to achieving President Biden’s climate goals and DOE is committed to keeping 100% clean electricity flowing and preventing premature closures,” Secretary of Energy Jennifer Granholm said.

“The Bipartisan Infrastructure Law makes this all possible by allowing us to leverage our existing clean energy infrastructure, strengthen our energy security and protect US jobs.”

The USD6 billion Nuclear Credit Program will allocate credits to reactors which are “certified” to say they are projected to cease operations due to economic factors, that cessation of operations would result in a projected increase in air pollutants, and that there is reasonable regulatory assurance that the reactor will continue to operate safely.

Credits will be allocated to selected certified reactors over a four-year period and can be awarded up until the end of September 2031, if funds remain available.

A Notice of Intent (NOI) and Request for Information (RFI) on the implementation of the USD6 billion Civil Nuclear Credit Program was announced on 11 February and published in the Federal Register on 15 February. The NOI allows potential applicants to submit voluntary, nonbinding expressions of interest in the programme, while the RFI seeks input from stakeholders on its proposed approach. A deadline of 17 March has been set for general responses, with responses specifically on certification to be sent by 8 March.

Hydrogen Shot

The department has also announced two RFIs to inform hydrogen programmes under the Bipartisan Infrastructure Law, with USD8 billion earmarked for regional “clean hydrogen hubs” to expand the use of hydrogen in the industrial sector and beyond; USD1 billion for a Clean Hydrogen Electrolysis Program to reduce costs of hydrogen produced from clean electricity; and USD500 million to support hydrogen manufacturing and recycling initiatives.

Most of the USA’s current production of hydrogen – about 10 million tonnes per year, compared with global production of some 90 million tonnes – is from natural gas through steam methane reforming, DOE said. Electrolysis technology, which uses electricity to produce hydrogen from water, “could allow for the production of hydrogen using clean electricity from renewable energy including solar, wind, and nuclear power,” it said.

The RFIs will help accelerate progress, reduce technology cost, and ramp up the use of hydrogen as a clean energy carrier, DOE said, and will also provide feedback to support its Hydrogen Shot effort to cut to cost of clean hydrogen to USD1 per 1 kilogram in one decade.

Responses to the Hydrogen Hubs Implementation Strategy RFI are due by 8 March and to the Clean Hydrogen Manufacturing, Recycling and Electrolysis RFI by 29 March.