Scotland has the potential to produce a huge amount of green hydrogen from untapped offshore wind and is ideally placed to supply the expected major demand centres around northern Germany over the coming decades.

But there is, of course, a huge amount of work to do for this to become a reality. While the UK is a leader in offshore wind generation, floating wind remains in its infancy and no hydrogen has been produced offshore at scale anywhere in the world.

Consultancy Xodus Group, in its The Green Hydrogen Revolution report launched today, sets out how the potential of Scotland’s territorial waters could be developed to help achieve the country’s 2045 net-zero target. Already, the Scottish government has set a target of 5GW of green hydrogen production by 2030.

Beyond the near term, Scotland has the capacity to generate a colossal 170GW of power from offshore wind, but its full development is likely to be highly constrained by limitations in the onshore power grid. If even a fraction of this potentially stranded resource is captured and used for green hydrogen, it would establish the country as a major producer. Xodus suggests that, in a plausible scenario where an additional 30GW of power is generated offshore, 100TWh/yr of green hydrogen is credible.

Ultimately, the viability of this idea comes down to economics. The cost of floating wind power, let alone producing green hydrogen offshore, will always be relatively high. But Scotland has the potential to cheaply transport hydrogen via pipeline—rather than expensively and inefficiently shipping it from the Middle East or North Africa in the form of ammonia or liquid hydrogen.

Transition Economist spoke to two of the experts behind the report: Graham Barton, senior field development study manager, and Jakub Vrba, renewable energy consultant. We discussed the competitive position of potential green hydrogen producers, the role of government support in bridging the price differential with grey hydrogen, the potential to repurpose infrastructure and the impact of Brexit.

There is huge potential for green hydrogen production in Scottish waters—but there are many rival potential sites. What is special about this location?

Vrba: The UK has long been the main driver of offshore wind development, and Scotland has huge potential for floating wind. But the power grid is already constrained and by 2030 there will need to be alternative routes to market for offshore wind projects. Even when considering electricity transmission to England, there would be a lot of untapped potential if we do not produce hydrogen. We see green hydrogen really taking off in the coming years.

Barton: People tend to quote costs at the point of production—such as solar hydrogen in North Africa at £1/kg—but things change when you add in transportation. Scottish green hydrogen has a part to play in the big German and Dutch markets that do not have the same indigenous renewables supply. They are keen for green hydrogen, but where from? Pipelines from Portugal or even further afield are complex projects—including repurposing pipelines, brownfield works and new pipelines in between. We could pipe hydrogen directly.

100TWh/yr – Target green hydrogen production

We are realistic, given competing sources. We believe 100TWh/yr is credible, and we estimate this could satisfy about 10pc of the long-term European market. Importantly, we also believe it would enable another 30GW of Scottish offshore wind to be developed, a resource that might otherwise remain stranded by grid constraints and distance from consumers.

Countries from Ireland to Norway could produce green hydrogen offshore. Would there be sufficient demand for all potential producers?

Barton: The volumes we will need by 2050 mean there will not be one individual or even dominant source—it will require 'all hands on deck'—and some of those sources will be more expensive than others. Scandinavian wind- or hydro-powered green hydrogen will be competitive. Ireland, like Scotland, does not have a huge domestic market and is looking to fully develop wind, but ship-based supply—as ammonia or liquid hydrogen—will remain much more expensive.

Will supply constrain consumption for the foreseeable future?

Vrba: Until 2030, the export market will be regional. Scotland needs an offtaker such as Germany, which is planning to import 5GW of green hydrogen by 2030. Scotland will supply some of that, as well as supplying the Netherlands and other parts of northern Europe. From 2030, we will see a more integrated market and longer distance shipping—that is when North Africa will start competing. By then, it will not be driven by individual projects—as production could be developed independently as the market would take up new supply.

Barton: The first European market for green hydrogen will be displacing the 400TWh/yr of industrial grade grey hydrogen used principally for petrochemicals and ammonia, and in high-temperature applications such as steel-making. Where demand sits near a cluster it may go to blue hydrogen—but demand in general is very dispersed and we think in many instances it will prove easier to switch to imported green hydrogen. There is a plentiful demand before we talk about introducing new sectors or switching—which are hampered by the inefficiency of conversion. The industrial sector is sizeable, so it is going to be supply- rather than demand-led over the next decade.

How much of the price differential between grey and green could be eroded away? Long term, what level of carbon tax would be necessary?

Vrba: Green and blue hydrogen will not be able to compete unless there is an incentive—whether a carbon price or government-led initiative such as contracts for difference. Definitely for the next decade, probably beyond.

There is not one price or tax, because hydrogen can be used across various sectors. It depends on the sector but a ballpark $100/t of CO₂ would help hydrogen penetrate most markets. For transport, the tax could be lowest because of the high retail price of diesel and petrol. But, for heat, even $100/t would be difficult because natural gas is very cheap and relatively low carbon compared with other fossil fuels.

Barton: The dominant factor in green hydrogen is the cost of electricity. Realistically, there is going to be a floor on the cost of power from wind turbines 150km offshore—it is never going to be the cheapest form of renewable energy. The cost of electrolysers in 2030 is anybody's guess—it was one of the questions we agonised over in our report. They are coming down faster than anyone ever imagined, but there will also be a floor.

“Green and blue hydrogen will not be able to compete unless there is an incentive—whether a carbon price or government-led initiative such as contracts for difference” Vrba, Xodus

The breakeven carbon price is probably around $100/t—but we need something above that to push uptake. Even $100/t is way above the EU ETS, which had long been below €20 and only recently above €40. But, in a way, hydrogen is already at cost parity with petrol in the UK because we pay the equivalent of over  £250/tCO₂e in fuel duty, which is effectively already a carbon tax.

Your report is less enthusiastic about the potential of repurposing gas infrastructure than some other studies.

Barton: It is tempting to treat repurposing as a silver bullet. It feels elegant and certainly will play a role in specific instances, but I think of it more as a potential opportunity to improve upon creating new infrastructure.

Interestingly, it is the older pipelines made from lower-grade steels that are more ductile and less susceptible to embrittlement. The more recent, fancier steels are worse for hydrogen than the older [X55 or lower] ones. Older designs are less sophisticated but sturdier—and the same is true for platforms.

You need also to look at its history. If a pipeline has been in wet gas service for 25 years, even with good corrosion inhibition, can it really be the basis of the next 25 years? Especially with a lighter molecule, integrity is vital.

We also should not forget that many pipelines will still be used for natural gas for many years to come. Hydrogen can be blended but would also then need to be deblended, at additional cost, if we want to use it to make ammonia or in petrochemicals.

Last week, the UK awarded the vast majority of its phase two funding to blue hydrogen and carbon capture and storage (CCS) projects. Is it interested in green hydrogen?

Vrba: It is tricky question, as we should not be choosing between blue and green. We need both. Blue hydrogen projects such as Acorn are required to get the sector up and running—and that will help green hydrogen develop.

Green hydrogen from offshore wind projects will take many years to develop. Scotwind projects will likely start generating after 2030—around the time large-scale green hydrogen projects could come online. But across EU countries and the UK, the long-term vision is shifting towards green. The Scottish government is very keen to support offshore wind and green hydrogen production, but it has to work closely with the UK government because, when it comes to revenue support, only the UK government can push ahead.

Barton: CCS is still some way from being developed at scale. Globally, only gigaton-level storage would make a real difference. CCS captures about 90pc of CO₂ and there are concerns about fugitive methane emissions—so blue hydrogen is not ‘zero’ carbon. And as we have plenty of existing CO₂ to capture already—why would you fill up valuable storage sites with CO₂ that you can avoid? That may be too simplistic, but the long-term direction has to be green.

“Scottish green hydrogen has a part to play in the big German and Dutch markets that do not have the same indigenous renewables supply” Barton, Xodus

I am not decrying the funding of clusters to keep Feed studies and pilot projects going. But until we make that next big step and get a robust fiscal regime in place that makes these projects truly commercial at scale, you wonder whether this is going to get stuck again. We have been here before, ten years ago, with CCS—a lot of money was spent but they all the projects stalled because there was no commercial driver. A lot will depend too on the bounce-back from Covid-19. Will the pandemic stall it, or launch it?

The EU has a world-leading hydrogen strategy. Might EU producers get preferential treatment? Does Brexit matter?

Vrba: Germany wants to import certified green hydrogen. As long as Scotland can prove its hydrogen has come from renewables and can compete on price, I see no reason why Germany would not import it. But Brexit will play a key role in funding for R&D and pilot projects. Scotland will find it difficult to tap these large funds whereas it will be easy for Ireland. That is where I see the danger.

Is the UK replicating the European R&D pools?

Vrba: It is aiming to, but I do not think it will be able to match EU funding. It would be amazing if that happened. Personally, I do not see it happening on the same scale, as if we were still part of the EU.

Your report highlights production potential of 170GW within Scotland’s legal maritime boundaries. What would be involved in achieving this?

Barton: The North Sea has led since the 1970s. It is always challenging, but we overcome it. The likes of Shell, BP and Equinor bring massive engineering experience and capability—they have done projects in the harshest environments all over the world.

$100/t – Carbon price that would start to make hydrogen competitive

If you can put a floating wind turbine out there, I am certain you can build a hydrogen pipeline. For transportation within northern Europe I suspect pipelines will always be cheaper than shipping, as you avoid the cost and inefficiencies of converting it into another state or compound such as ammonia

Offshore wind around Orkney and Shetland will be hard to get onto the grid at scale—that same remoteness is why terminals such as Sullom Voe and Flotta were developed for oil export. Repurposing these terminals as regional hydrogen production and export hubs makes a huge amount of sense. Likewise, the Outer Hebrides had some of the very earliest Scottish hydrogen trial projects.

What are the next steps?

Vrba: The Dolphyn Project will be the first floating wind turbine with hydrogen production offshore anywhere in the world. Once proven, the next step would be to step away from demonstration projects to a proper pilot. This would involve a floating windfarm of more than 100MW—whether the hydrogen is produced on- or offshore is less important. It is more important to demonstrate that offshore wind can produce hydrogen at scale. Then, when we look at 1GW+ windfarms 100km out, hydrogen production offshore would start to make sense—but this is definitely not something we will see even in the next ten years.

Barton: If we did it at scale today, hydrogen would be something like $7/kg and no one would buy it. The technology will happen. What is most needed is the commercial environment—the pricing, the economics—and that must be market-led. We will only get beyond subsidised demonstrator projects once the commercial environment allows companies to undertake multiyear, billion-dollar projects.

Xodus Group’s The Green Hydrogen Revolution is available to download.

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Author: Alastair O’Dell<BR>Senior Editor