Hydrogen Update

The Dutch government announced the EUR 1 billion green hydrogen auction to support capital and operating expenditures for green hydrogen. This state aid, paid monthly to the producer, will fill the 80% price gap between grey and green hydrogen for five to 10 years. The subsidy will be adjusted based on the market price of grey hydrogen and a government-set benchmark. If the market price falls below a minimum threshold, the Dutch government will cover the difference up to a cap of €9/kg. This auction, which opens in October 2024, is available for projects with a 0.5 MW or more capacity, aiming to bridge the cost gap and support the transition to green hydrogen.

At the same time, we know that increasing efficiency, cutting costs, and overcoming midstream technical challenges are imperative for green hydrogen to become competitive. Some innovations centre around membranes, higher current densities, using abundant sea water, solid oxide cells for higher temperatures, and coatings for catalysis performance. 

TNO Study Highlights Investment Costs in Water Electrolysis

TNO published a study to assess the LCOH through water electrolysis in the Netherlands (most hydrogen today is produced from methane – SMR). The report focusses only on cost; no subsidies or operating income is assumed. The investment costs are estimated at EUR3,05/kWe and EUR2,063/kWe for a 100MW and 200MW electrolyser respectively, resulting in LCOH of EUR12-14/kg. The investment cost has shown an upward trend in recent years due to increases in the cost of labour, materials and energy, and interest rates as well. In addition, there is still limited manufacturing capacity for electrolysers in Europe and the US. 

Electricity Costs Dominate Green Hydrogen Production

Of these €14/kg, about €5 are capital costs. Only 30% of these costs are due to the cost of electrolysers, so even if the price of electrolysers were to drop with mass production, it would have little impact on the capital cost (if the cost of electrolysers were halved, the capital costs of green hydrogen would still be €4.2/kg). The rest of the capital cost is due to compressors, plant balancing systems, and interest rates.

The remaining €9/kg is due to the price of electricity (€5 for purchasing electricity + €2 for connection costs + additional grid costs). The assumption behind these numbers is that green electricity is purchased through fixed-price supply contracts at €70-80/MWh, an amount in line with current European PPAs.

The incentives needed for hydrogen production plants to compete with steam reforming would then amount to €3300/kW, compared to the previous estimate of €2200/kW. This obviously represents a disincentive for industries to sign long-term off-take agreements for hard-to-abate processes. Alternative hydrogen production technologies like VHTR are increasingly considered, and TNO highlighted the importance of working on electrolysers of 2nd and 3rd generation, possibly with radically new designs, to abate costs and increase efficiencies.

EU Calculator for LCOH Modelling

The Clean Hydrogen Partnership launched an LCOH calculator, funded by the EU commission, to enable modelling of renewable hydrogen costs across 27 EU countries. 

The calculator allows the calculation of hydrogen production costs via low-temperature water electrolysis (alkaline or PEM) in the EU27 countries, Norway, or the UK. It provides a selection of four different electricity sources (Wholesale, PV, Onshore, or Offshore #wind).

Some assumptions are: 

• For PV and onshore wind, it is assumed that a direct connection to the electrolysis unit is used, excluding grid fees and electricity taxes. For wholesale electricity and offshore wind, it is assumed that grid connection is used, including grid fees and electricity taxes.

• The default values always show ‘0’ for subsidies and additional revenues. However, any subsidies or additional revenues that a project may receive can be captured in the user-specified values.

• The calculator assumes the cost of capital as 6% and the number of operating hours as 4,000 per year when using wholesale electricity (by taking the average of the 4,000 cheapest hours). Other OPEX reflected in the LCOH cost include both the stack replacement costs and other OPEX as expressed in the table as a function of CAPEX.

IRENA's Perspective on Global Hydrogen Economics

Turning to IRENA for some big-picture thinking: with long-term average fossil fuel prices of USD 75/bbl for oil and USD 4-6/GJ for natural gas, renewable hydrogen is two to three times more expensive than fossil fuels. Hydrogen pipelines can be 10-50% more expensive. Fuel cells and storage tanks for road transport are multiple times more expensive than internal combustion engines. Synthetic fuels for aviation can currently be three to six times more expensive than jet fuel from fossil oil. Compared to fossil-based options, the cost premium for renewable pathways can be 50-75% for ammonia, 150% for methanol and 30-40% for steel.

The higher energy density of hydrogen-derived commodities effectively increases the distance that energy can be transported cost-effectively, connecting low-cost renewable energy regions with demand centres with either limited or costly renewable energy potential. Global energy trade through hydrogen derivatives would provide economic benefits as importing countries can tap into cheaper (than domestic) resources, improving the resilience of the system since there are alternative ways to satisfy final energy demand, and hence strengthening energy security.

Hydrogen trading, however, will not be defined solely by economic benefit. In the long term, when technologies have reached full maturity and are deployed at large, it is expected that importing countries will be able to count on multiple alternatives within a small cost range. Therefore, trading partners will be primarily defined by non-economic factors.