Edinburgh-based energy market research consultancy Delta-EE has written that Europe is on track to reach 2.7 GW of operational hydrogen electrolyzer capacity by 2025. This is mostly because of EU public support coming from the EU green deal and the IPCEI Hydrogen initiative. “However, time is running out to establish the many projects on the hundreds of megawatts scale required to achieve an EU target of 6 GW by 2024,” the company stated.
According to the Scottish consultancy’s new Global Hydrogen Intelligence Service, nearly half of all European electrolyzer capacity is in Germany while no other country has more than 10 MW installed. “The sector is expanding fast; the first major projects in several countries (e.g. Spain, Netherlands, Denmark) will be at the tens of megawatts scale in 2021/22 and will soar towards the hundreds [of] megawatts by 2025. A key factor in this growth will be the increase in manufacturing capacity of electrolyzer manufacturers,” the company explained, mentioning Nel Hydrogen, ITM Power, Cummins and McPhy, which “are all building factories capable of producing hundreds of megawatts, if not gigawatts of electrolyzers a year.”
The competitiveness of the different transportation options for hydrogen depends on the distance over which hydrogen is transported, as well as on scale and end-use, according to the European Network of Transmission System Operators for Gas, ENTSOG; the European association of gas infrastructure operators, GIE; and Hydrogen Europe, a European association representing the interest of the hydrogen and fuel cell industry. “If hydrogen needs to be shipped overseas, it generally has to be liquefied or transported as ammonia or in liquid organic hydrogen carriers (LOHCs). For distances below 1,500km, transporting hydrogen as a gas by pipeline is generally the cheapest delivery option; above 1,500km, shipping hydrogen as ammonia or a LOHC may be more cost-effective,” wrote the three European associations last month in a report. They see, in blending, “an easy entry point into the hydrogen economy,” defining it as a cost-effective transitional option, despite the modifications and related investments needed, especially for compressors. “Different compressor models react in different ways to hydrogen blends,” reads the report, explaining that the needed investments will also depend on the share of hydrogen. A complete switch to a 100% hydrogen pipeline will require installing new turbines or motors and new compressors. Capacity will then play a key role in the financial considerations. “Analyses by some gas TSOs show that operating hydrogen pipelines at less than their maximum capacity gives much more attractive transport costs per megawatt-hour transported, as additional, expensive, high-capacity compressor stations – and corresponding energy consumption – can be avoided.” Methane has three times the calorific heating value per cubic meter of hydrogen but “the same gas pipeline today transporting mainly natural gas, can transport about three times as many cubic meters of hydrogen during a given period and thus deliver roughly the same amount of energy.” Hydrogen is a much smaller molecule than methane. The tightness of the system and the material used for sealing need to be chosen accordingly, explains the report. The re-purposing costs of typical transmission pipelines for 100% hydrogen transportation are expected to be between €0.2 million and €0.6 million per kilometer. The three associations also explained that there are currently no EU-wide technical specifications related to the quality of hydrogen transported via dedicated hydrogen pipelines in gaseous form. “The absence of a harmonized EU regulation could lead to a fragmentation of the hydrogen market,” say the associations in the report, also considering final transportation costs (levelized costs of €2.30 to €4.40 for the transport of 1 MWh over 1,000km); the centrality of Europe in the ongoing projects; storage of hydrogen (in salt caverns); and the role of ports and offshore platforms.
Bahrain, Kuwait, Oman, Qatar, Saudi Arabia, and the United Arab Emirates are among the most competitive locations globally to produce and export green hydrogen and derivatives, say Germany-based industrial initiative Dii Desert Energy and Munich-headquartered management consultancy Roland Berger. The lowest-cost solar and wind energy globally make the GCC region potentially one of the most competitive for hydrogen production. A recent tender in Saudi Arabia was awarded for a price of $0.0104/kWh. Taking advantage of the oil and gas economy, significant funding is available through sovereign funds as well as international investors. Furthermore, the region has a proven track record in building and operating export infrastructure and it has a central location for future large-energy-demand markets such as the European and East Asian markets,” reads the report, adding that hydrogen valleys could also enable local hydrogen economies.
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