The EU’s Copernicus Climate Change Service and other meteorological organisations confirmed in January that 2024 was the first year in which the world experienced temperatures of more than 1.5°C above pre-industrial levels. Meanwhile, wildfires have raged across southern California and a climate sceptic has retaken the helm of the world’s largest economy.
Time, perhaps, to double down on hydrogen production. In London, the government has done just that. Since coming to power, Labour has doubled its low-carbon hydrogen production target to 10 GW by 2030.
10 GW of capacity would produce about 1.1 million tons of hydrogen per year, assuming the capacity runs 60% of the time and the efficiency of the electrolysers is 75% – an expected improvement on current levels. This is the equivalent of about 3.65 billion cubic meters (Bcm) of natural gas, or 5.75% of total UK gas consumption in 2023.
As the UK produced only 34.5 Bcm of gas in 2023, the produced hydrogen would displace gas imports. Hydrogen is a win when it comes to both energy security and greenhouse gas emissions.
Subsidy bill
That’s where the good news ends. Low-carbon (AKA green) hydrogen is very expensive to produce and there is no ready market for this quantity of hydrogen, even if the capacity target were reached.
According to the European Hydrogen Observatory (EHO), the UK produced and consumed 474,000 tons of hydrogen in 2023, almost entirely in the refining and chemicals sectors. This hydrogen is high carbon, produced on-site to add value to other feedstocks and does not incur transportation costs.
The subsidies – or ‘business model’ in current parlance – to sustain 10 GW of low-carbon hydrogen capacity would be high.
The EHO estimates the current cost of green hydrogen production in the UK at €4.9/kg using renewable energy directly and at €9.7/kg using grid electricity. This is the equivalent of about $38/MMBtu and $75/MMBtu, respectively, versus current prices on the Dutch TTF for natural gas of just under $14/MMBtu.
The UK’s first hydrogen project allocation round (HAR1) returned an average strike price of £241/MW for 125 MW of capacity, equivalent to just over £9/kg.
This implies (if the government’s target is met in 2030) a subsidy bill of €3.4 billion/yr based on renewable electricity, or up to €5.9 billion/yr based on grid electricity. The government plans a tax on gas shippers to cover some of the outlay, a levy that will most likely find its way to consumers in some form.
Wasted wind energy?
Part of the idea behind hydrogen production is that it can mop up excess wind energy at low, perhaps zero, cost. Wind curtailment costs in the first nine months of 2023 amounted to £1.1 billion – the majority of which was paid to gas generators to replace the power generated from wind, which could not be connected to demand owing to a lack of transmission capacity.
However, while there appears to be a lot of excess generation when it is reported as ‘wasted’, or presented in money terms as grid constraint payments in newspaper headlines, there isn’t that much when it comes to generating large amounts of hydrogen.
In the first nine months of 2024, the curtailment volume was 12.2 TWh, which is enough to produce 244,000 tons of hydrogen, assuming 67% electrolyser efficiency, equating to 50 kWh per kg of hydrogen produced.
However, hydrogen capacity cannot be based on surges in excess power. Moreover, gaining a low price for constrained power requires some form of locational pricing, which is being considered under the Review of Energy Market Arrangements.
Variable power a bad fit
Excess wind generation is expected to grow as wind deployment moves ahead faster than grid investment, but hydrogen production is about bulk output, while excess wind generation is variable. Electrolysers ideally need to run as much of the time as possible, to keep per kg production costs down, which means a firm energy supply.
There are also operational requirements that require steady-state operation. According to water treatment specialists Lenntech, alkaline and PEM electrolysers are flexible enough to follow short-term fluctuations in wind and solar power generation, but the flexibility of the system overall is limited by the compressors rather than the electrolyser cell stack itself.
Run at low capacity and the capital cost of the hydrogen plant is spread across less production, raising per-unit costs. Run at high capacity, say 90%, and the capital cost is spread across much more production.
However, 90% is significantly higher than the capacity factors of even offshore wind farms so grid electricity would be required, exposing hydrogen plants to a higher average electricity price over the course of a year – similar to any other industrial enterprises. In addition, by adding power demand, hydrogen plants would inevitably create a price for what is now deemed zero-cost power.
Competitive hydrogen production requires a clean electricity source or system that provides very low-cost electricity on average across the year – not just occasionally.
Efficiency gains
Cost reductions also need to come from improvements in electrolyser performance and lifespan, as well as improvements in associated infrastructure known as the Balance of Plant (BOP), reducing the capital cost per kg of hydrogen produced.
The BOP typically carries roughly the same cost share as the electrolysers and presents opportunities for efficiency gains. Meanwhile, solid oxide electrolysers are far more efficient than either alkaline or PEM, but their lifespan at present is short and the capital costs high.
Just as with batteries and solar panels, greater manufacturing volume should result in steady gains in electrolyser and BOP costs and performance. Electrolyser efficiency is of particular importance because it reduces the cost of electricity per kg of hydrogen produced.
BOX: Water use a concern? Yes and no.
© Supplied by NABuild and will they come?
Producers can be persuaded to produce hydrogen – if subsidised to an affordable level, so that the subsidies derisk the investment – but they also need off-take agreements to convince financiers that they will be able to sell their product when produced.
Consumers typically only adopt new technologies of their own volition if there is a clear cost and/or performance advantage. Hydrogen doesn’t have a performance advantage that accrues directly to the consumer or industrial enterprise (beyond saving the planet), and requires investment in terms of new or modified appliances and equipment.
Demand for such a product may struggle to emerge naturally, even if marketed at a price similar to incumbent choices. Lower down the hydrogen hierarchy, potential off-takers will have decarbonisation alternatives – for example direct electrification, which could prove cheaper.
As such, a strategy to create demand appears just as necessary as providing subsidies for production.
Industry will be the prime user of hydrogen as a value-enhancing intermediate product, rather than individual consumers. It will be targeted at the hardest areas of the economy to decarbonise, but even these users may require a regulatory push and/or incentives, which would again raise the cost to the exchequer.
Hydrogen production and use is desirable. It appears to be an essential part of the end game. But getting it to the point of affordability and creating demand will take time, which is lacking. The danger is that the subsidy burden proves too high, the government pays a political price and a nascent sector finds the financial rug pulled from beneath its feet before it can walk alone.
Ross McCracken is a freelance energy analyst with more than 25 years experience, ranging from oil price assessment with S&P Global to coverage of the LNG market and the emergence of disruptive energy transition technologies.
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