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Interest in international hydrogen trading is rising rapidly. New announcements of credible major export initiatives are occurring frequently.
But there remain doubts about the rate of development of the infrastructure needed for importing hydrogen at scale, whether as hydrogen or via carriers such as ammonia.
The role of hydrogen imports has gained increased importance as Russia’s invasion of Ukraine continues, and the world digests its ramifications for the future energy system. Hydrogen’s significance as a perceived solution to energy security increasingly parallels its popularity as a missing link in large-scale decarbonization of hard-to-abate sectors of the global economy.
The European Union’s immediate response to the Russian invasion has been a push to urgently and dramatically reduce its dependence on Russian hydrocarbons. In the near term, this will necessitate liquefied natural gas imports from other countries.
In the medium and longer term, however, the EU’s policy is clearly to promote hydrogen as the imported energy of preference. This brings with it the twin benefits of alleviating dependence on Russian imports and facilitating transition to nonhydrocarbon energy sources.
The EU’s recently announced REPowerEU strategy for reducing its energy dependence on Russia has raised the target for hydrogen in the bloc’s energy mix to 20 million metric tons per year by 2030, with imports expected to meet 50% of this target. Across individual EU countries, hydrogen import-focused projects have rapidly taken shape since the start of Moscow’s invasion of Ukraine in February.
Often, these efforts are tied to the construction of new LNG import capacity that will subsequently be converted to enable hydrogen or ammonia imports, or otherwise be engineered to be hydrogen-ready in the longer term.
Proposals for hydrogen-ready terminals include several in Germany — Uniper SE’s revived plan for an LNG terminal in Wilhelmshaven, the German LNG consortium’s plant in Brünsbuettel, and the planned Hanseatic Energy Hub GmbH facility in Stade.
E.ON UK PLC is partnering with Tree Energy Solutions GmbH to explore building a green gas terminal in Wilhelmshaven, and is working with Fortescue Future Industries to develop a hydrogen supply chain between Australia, Germany and the Netherlands. Also in the Netherlands, NV Nederlandse Gasunie, HES International BV and Royal Vopak NV have joined forces to develop an import terminal for green ammonia.
To enable appropriate regulation for this burgeoning sector, the EU has proposed a draft directive laying out a common set of rules for internal markets in renewable and natural gases and hydrogen. This draft is framed to facilitate regulation of both hydrogen and LNG terminals—including hydrogen regasification and associated ancillary facilities.
A consistent regulatory framework will be important to give the sector clarity and stability, and hence enable projects to proceed more confidently and efficiently.
In addition, and importantly, for imported reconverted hydrogen to constitute green hydrogen—and to thereby benefit from the various rules regarding renewable fuels of nonbiological origin—the imported green ammonia would have to comply with the various standards for green hydrogen set out in the European Commission’s proposed amendments to the Renewable Energy Directive known as RED III.
Debate continues over whether the optimal delivery mode for hydrogen is liquefaction, conversion into ammonia or methanol, or use of a liquid organic carrier.
Most large-scale projects under development are envisaging that conversion to ammonia is likely to be the most effective method of long-distance transportation, given that ammonia is currently much cheaper and easier to store than hydrogen itself, whether in gas or liquid form.
As a result, it is likely that during the early stages of emergence of international trade, green hydrogen will be converted into ammonia or some other derivative liquid for transportation prior to being shipped internationally.
Where the end user requires hydrogen, this will necessitate the ammonia or other derivative liquid to be reconverted or “cracked back” to gaseous hydrogen at its destination. Thus, current plans for hydrogen-ready terminals will need to provide import, storage and crack-back infrastructure to enable the delivery of hydrogen to end users.
Given the early-stage status of most new hydrogen import initiatives, there are few project details currently in the public domain. Nonetheless some details are starting to emerge.
For example, RWE AG—one of the partners in the German LNG consortium that is developing the Brünsbuettel project—has disclosed some of its plans for developing an ammonia terminal at the same location. The plan is aimed at preparing the future LNG facility at the site for conversion to hydrogen imports.
While the consortium is developing the LNG plant, the ammonia terminal will be developed exclusively by RWE. RWE has said that it anticipates 300,000 tons per year, or TPA, of green ammonia arriving in Germany by 2026.
RWE intends to incorporate the entire value chain into the project—from the import process to hydrogen reconversion, transportation and utilization by customers. RWE projects that the second phase of the project’s development would coincide with ammonia import volumes rising to 2 million TPA.
This phase of expanding the terminal’s capacity would entail the construction of an industrial-scale unit for cracking ammonia back to hydrogen, as well as development of a
dedicated hydrogen pipeline. The company estimates that investment requirements could run into several hundred million euros.
Gasunie, HES and Vopak are also targeting a start date of 2026 for their ammonia import project, known as the ACE Terminal, in the Netherlands. The partners have cited the strategic location of their project, with direct access to the North Sea, a connection to the industrial center of Rotterdam, and Gasunie’s infrastructure for transport and storage. Gasunie is also in the process of developing a national hydrogen transport network, to which the terminal would be connected.
The partners are currently in the basic design and permitting phase and anticipate a final investment decision on the terminal in late 2023. According to public information, the terminal will allow for storage of ammonia in existing infrastructure, and for the possibility of cracking ammonia back into hydrogen. The ACE Terminal site also contains space to expand both cracking and storage capacity, according to available information.
This approach of privately built reconversion or crack-back infrastructure will raise challenges for the wider hydrogen sector. The EU’s draft directive anticipates the potential for access-related issues in these circumstances, and contemplates that EU member states must “ensure the implementation of a system of third party access to hydrogen terminals” and “monitor conditions for third party access to hydrogen terminals.”
The draft directive envisions a similar, albeit simpler, regime to that used for LNG that will apply to hydrogen network pipelines, with added scope for a derogation from equal-access requirements available to member states until Dec. 31, 2030. Industry players will need to be aware of the impact of these requirements in their wider planning assumptions.
While few further details are currently available, the RWE and ACE plans provide insights into the scale of import infrastructure likely to be required where global industry adopts ammonia as the transit product for large-scale international hydrogen trade.
If several of these planned ammonia terminals are ultimately built, and if the international hydrogen trade adopts ammonia as the favored intermediate product, delivery of vessel-borne hydrogen by other means—including via liquefaction or liquid organic carriers—could be pushed back further both in terms of feasibility and timelines.
This is because the carrier of choice will have been de facto determined by import capability and capacity, and by the need to balance the speed of building import infrastructure with regulatory requirements in relation to third-party access to privately built infrastructure.
As to shipping, consultancy Wood Mackenzie Ltd. estimates that, as of January, seaborne trade in ammonia amounted to around 20 million TPA. Scaling up seaborne trade and the related supply chains would be considerably easier than establishing altogether new ones for different types of hydrogen-bearing vessels.
For example, compressed hydrogen vessels have yet to be commercialized. The world’s first liquefied hydrogen carrier only completed its first delivery at the start of 2022. While technological advances and new investments are expected by many to help with the uptake of other seaborne transportation options over time, most new entrants to the maritime hydrogen trade will favor the option that is best established at the time of their first cargo’s availability.
Separately from its ammonia plans, RWE has partnered with German gas transmission system operator Open Grid Europe GmbH on the H2ercules project to expedite the domestic hydrogen infrastructure build-out. The project will entail connecting electrolyzers, storage facilities and import facilities in the north of the country with industrial consumers in the west and south of Germany.
This project, which is anticipated to require investments of about €3.5 billion, highlights another factor that hydrogen importers will need to ensure: that their terminals are connected to their customers.
As hydrogen infrastructure grows, it will become easier to develop and connect import capacity to demand centers over the longer term. But the costs of developing this infrastructure will remain considerable.
Another initiative, the European Hydrogen Backbone, which recently raised its targets in line with REPowerEU, now envisions a European hydrogen network comprising around 53,000 kilometers of pipelines by 2040, requiring investment of €80 billion–€143 billion. This network would be linked to European green hydrogen production hubs, but will also be vital for transporting hydrogen from import terminals to European consumers.
While the proposed networks will require a significant proportion of existing natural gas pipelines to be repurposed for the transport of hydrogen blends or pure hydrogen, new import terminals would also require new pipelines. Due to the differing properties of hydrogen and natural gas, existing natural gas pipeline networks and other infrastructure will probably be unable to carry the amount of hydrogen needed to achieve Europe’s decarbonization objectives.
Technical analysis concludes that a 20% blend cap is likely to be the maximum appropriate to much existing infrastructure. The 2022 Joint Research Centre technical report from the EU, “Blending hydrogen from electrolysis into the European gas grid,” considers two threshold levels—5% and 20%—as being potentially applicable from 2030 onwards.
The blending cap of 20% is driven by technical challenges arising from potential issues with damage to transport pipelines, storage sites, compressors, seals and meters that would result from a higher blend mix. Additionally, some industrial consumers, e.g., the glass and ceramics sectors, as well as existing domestic heating boilers and cookers, are unable to handle more hydrogen-rich blends.
It is also worth remembering that many EU jurisdictions still do not permit the blending of hydrogen into domestic natural gas networks, or currently permit only much lower percentages than 20%.
To address these challenges, enhancements made to the RePowerEU strategy on May 18 have reemphasized the EU’s commitment to rapidly building out hydrogen infrastructure in Europe. The European Commission is setting aside an additional €200 million of funding for hydrogen research, and has incorporated further detail on the Hydrogen Accelerator plans included within RePowerEU.
The commission has called on the European Parliament and European Council to increase subtargets relating to hydrogen for specific sectors. The commission supports the development of three major hydrogen import corridors—via the Mediterranean, the North Sea and, once conditions allow, Ukraine.
The commission intends to map out preliminary hydrogen infrastructure needs by March 2023 and set up a dedicated work stream on joint renewable-hydrogen purchasing under the EU Energy Platform.
Aside from intracontinental infrastructure requirements, signs are emerging of efforts to establish fixed intercontinental links between hydrogen suppliers and European consumers.
Subsea and onshore international pipelines from hydrogen exporting countries would offer a way to circumvent the requirement for import terminals and related infrastructure—including related concerns about the timing, cost, energy efficiency and carbon intensity of ammonia crack-back infrastructure—and connect directly to newly hydrogen-ready pipelines within the EU.
Last year, Saudi Energy Minister Prince Abdulaziz bin Salman said his country was prepared to deliver piped green hydrogen to Europe, if the economics allow it. And Algeria has expressed its intention to start blending hydrogen into the natural gas it exports to Europe, including via pipeline, ultimately with the intent of replacing that gas blend with hydrogen altogether.
Similarly, Morocco is considering blending hydrogen into natural gas being transported to Spain via the Maghreb-Europe pipeline. However, that pipeline is currently offline amid an ongoing diplomatic dispute with neighboring Algeria, where it originates. Spain’s Cepsa has also unveiled a proposal to build a new pipeline for transporting hydrogen from Morocco to Spain.
Italy, meanwhile, is eyeing potential hydrogen imports from Algeria and Tunisia via pipeline. In November 2021, Italian companies Eni SpA and Snam SpA struck a deal whereby the latter agreed to buy a 49.9% stake in companies operating two pipelines connecting Algeria and Italy via Tunisia.
The companies described the pipelines as a strategic route for the security of Italian gas supply, and said their partnership was also aimed at enabling potential development initiatives within the North African hydrogen value chain. The European Hydrogen Backbone has identified the route to Italy from Tunisia and Algeria as one of five key future supply and import corridors for hydrogen.
Libya has also been identified as a potential source of hydrogen supply to Europe. But given how oil and gas production there is currently languishing amid ongoing political volatility, this option is seen as less likely in the nearer term.
Again, regulation is still catching up with geopolitical planning. The draft directive classes both intra-EU hydrogen interconnector pipelines and pipelines connecting the EU with exporting nations to be within the scope of hydrogen networks. It contemplates requiring that such pipeline networks should be separated from activities of energy production and supply, in the same way that supply and transport of LNG are already unbundled.
Hydrogen developers and would-be offtakers and consumers need to carefully evaluate potential midstream bottlenecks and trends when developing their business plans, as well as carefully tracking the evolving EU regulatory framework in this space.
It is likely that recent geopolitical events will help to accelerate overall development timelines for hydrogen importation plans, with the EU proposing in a new commission recommendation and targeted amendment to the Renewable Energy Directive to ease and streamline permitting for green energy projects. These new EU provisions aim to recognize renewable energy as being an overriding public interest, and to tackle slow and complex permitting for major renewable projects—including green hydrogen.
Nonetheless, it will take time to build new import capacity, as demonstrated by the 2026 targets, and to grant the range of third-party access rights to resulting terminals and hydrogen pipeline networks found in LNG and other sectors, as witnessed by the derogation offered to member states from the proposed unbundling requirements until 2030.
For the moment, the need to expand import capacity represents a major potential risk factor for the EU’s hydrogen targets. And the need to deliver this expansion quickly and effectively will challenge the EU’s regulatory framework to keep pace with this rapidly developing sector.