There is one number for hydrogen transport that appears in nearly every deck, and it is worth reading it the way a credit committee would: not the value, but the footnote.
The number, and footnote 23
Figure 1
The transport cost, and what it is a cost of
Cost of transporting hydrogen 1,000 km along an average stretch of the European Hydrogen Backbone, at a load factor of 5,000 hours per year.
Medium-cost scenario: €0.15/kg, equivalent to €4.5 per MWh.
€4.5–8.7 per MWh, if transported entirely via dedicated subsea offshore pipelines.
The medium-cost onshore scenario is €0.15/kg. Every figure here is from April 2022: the study's own November 2023 update restates capital cost per kilometre but does not restate this levelised cost, and no later EHB publication does either.
Source: European Hydrogen Backbone, A European hydrogen infrastructure vision covering 28 countries · Data as of 2022-04
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| Route | €/kg per 1,000 km | €/MWh |
|---|---|---|
| Onshore, range | 0.11–0.21 | 3.3–6.3 |
| Onshore, medium-cost scenario | 0.15 | 4.5 |
| Offshore, dedicated subsea | 0.17–0.32 | 4.5–8.7 |
The European Hydrogen Backbone puts it plainly:[1]
Transporting hydrogen over 1,000 km along an average stretch of the onshore hydrogen backbone, as presented in this report, would cost €0.11 – €0.21 per kg of hydrogen transported (€3.3 - €6.3 per MWh), with €0.15 per kg (€4.5 per MWh) for the scenario with medium cost estimates.
That is a careful, well-documented figure. And attached to it, in footnote 23, is the sentence that decides it:[1]
This study considers the backbone from an infrastructure investment perspective and does not take a strong stance on the exact level of network utilisation. A load factor of 5000 hours per year is deemed reasonable, cognizant of the fact this value will change depending on future market developments – and impact resulting costs accordingly.
Five thousand hours out of 8,760 is a 57% utilisation of the pipe. The source does not hide this and does not overclaim: it says the value will change and that the cost will change with it. That is exactly the right way to publish a modelled cost.
The problem is entirely downstream. By the time €0.15/kg has been through three decks and a consultant's summary, the footnote is gone, and what arrives at a project meeting is a constant.
And the number is four years old
The EHB's own November 2023 update restates capital cost per kilometre — 20-inch onshore at €1.80M/km, 36-inch at €3.20M/km, 48-inch at €4.40M/km, compressors at €4.0M/MW — and records the input inflation behind it: producer price indices up 47% for steel tubes and pipes, 48% for copper, 52% for aluminium and 125% for electricity generation and transmission, against 2019.[2]
What that update does not do is restate the levelised €/kg per 1,000 km. Neither does any later publication in the series.
So the position today is that the sector's standard transport cost was computed on April 2022 inputs, at an explicitly non-committal utilisation assumption, and both of those point the same way. This page does not compute what the updated figure would be — that would require the model, not the report. But a figure whose inputs have moved by roughly half and which has not been republished should not be carried into a project model as a constant.
Shipping costs energy, and the amounts are published
Figure 2
What each step of the shipping chain costs in energy
Energy consumption of each conversion step, as a share of the energy contained in the hydrogen.
IRENA describes this as high energy consumption for liquefaction, currently equivalent to 30-36% of the energy contained in the hydrogen.
Table 1.1: high (12-26%) energy consumption for ammonia synthesis.
Table 1.1. Section 2 of the same report states losses of at least 15% and up to 33% in the reconversion step.
These are steps, not a chain: a given route uses one carrier, not all of them. IRENA's Table 1.1 gives 13–34% for reconversion while the body of Section 2 gives 'at least 15% and up to 33%'; the chart shows Table 1.1. The IEA's 2026 review reaches the same order independently, putting shipping that must deliver pure hydrogen at over 30% of hydrogen's energy content.
Source: IRENA, Global hydrogen trade to meet the 1.5°C climate goal: Part II · Data as of 2022-04
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| Step | Share of hydrogen's energy content | Location in source |
|---|---|---|
| Liquefaction | 30–36% | Executive summary and Table 1.1 |
| Ammonia synthesis | 12–26% | Table 1.1 |
| Reconversion (cracking) | 13–34% | Table 1.1 |
| Reconversion (cracking) | at least 15%, up to 33% | Section 2, same report |
Where a pipeline does not exist, hydrogen moves as a liquid or as a carrier, and each conversion is paid for in the product itself. IRENA gives the numbers for each step as a share of the energy in the hydrogen: liquefaction at 30–36% today, ammonia synthesis at 12–26%, reconversion in the importing region at 13–34%.[3]
The IEA, four years later and independently, lands in the same territory:[4]
However, where pure hydrogen is required at the point of use, shipping implies minimum costs of around USD 2/kg H₂ and energy use above 10 kWh/kg H₂, equivalent to over 30% of hydrogen's energy content, due to intensive liquefaction or reconversion steps, such as ammonia cracking.
These are not obscure numbers and they are not contested. The useful discipline is narrower than "remember the losses": it is to be specific about which steps a given route actually incurs, because a route that delivers ammonia as ammonia does not pay the cracking penalty, and one that delivers pure hydrogen does.
The reconversion step has not been built at commercial scale
This is the finding that most changes how an ammonia import route should be underwritten, and it comes from the companies building it.
Air Liquide's ARCAS unit at the Port of Antwerp-Bruges is the largest in the world, and Air Liquide describes it as:[6]
the world's first industrial-scale ammonia cracking pilot unit with a 30 tons per day ammonia to hydrogen conversion capacity
A pilot. Thirty tonnes a day of ammonia in. The word is the operator's own.
The leading technology licensor is equally direct. thyssenkrupp Uhde states that by mid-2025 it considers ammonia cracking to be at TRL 6-7, and that "neither the catalyst nor the ammonia burners have been installed in commercial-scale crackers".[7] Its stated commercial ambition is capacities above 5,000 tonnes per day of ammonia.[7]
Between 30 tonnes a day operating and 5,000 tonnes a day intended, there are more than two orders of magnitude and no completed step in between. The nearest commitment is a framework agreement between Uniper and thyssenkrupp Uhde covering licence packages for up to six plants totalling 7,200 tonnes a day, at pre-FEED stage, with FEED scheduled to start at the end of 2026, and a demonstration plant at Gelsenkirchen-Scholven of 28 tonnes a day scheduled to go online at the end of 2026.[8]
A framework agreement is not an order and pre-FEED is not a project. For a model that imports ammonia and delivers hydrogen, the cracking step is first-of-a-kind risk at the scale required, and it should be priced and scheduled as such rather than entered as an efficiency.
The corridor that moved four years, and then split
Figure 3
One corridor, four ministerial positions
The hydrogen pipeline of the Delta Rhine Corridor, as each official document has dated it.
The June 2024 letter records that the earlier assumption was that the pipelines, including the hydrogen pipeline, would be ready for use at the end of 2028.
The letter states the planning of the first modalities shifts by four years against the previously communicated schedule, and attributes it to the choice of an integrated spatial procedure.
The same decision removed ammonia and the direct-current cables from the corridor's scope.
Gasunie's current wording is 'installed', not 'in service'. The exploratory phase opened on 5 September 2025.
The 2028 date was itself already a revision, set in a letter of 5 October 2023 — the pre-2023 commitment is not recoverable from these documents. And Gasunie's current wording is that the pipelines will be 'installed' between 2031 and 2032, which is not the same claim as entering commercial service; no in-service date is published.
Source: Kamerbrieven of 27 June 2024 and 5 December 2024; Gasunie project pages · Data as of 2026-08-30
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| Document | Date of document | Hydrogen pipeline ready |
|---|---|---|
| Kamerbrief of 5 October 2023, as recorded later | 2023-10-05 | end 2028 |
| Kamerbrief, Minister Jetten | 2024-06-27 | 2032 |
| Kamerbrief, Minister Hermans (scope decision) | 2024-12-05 | 2031–2032, to Boxtel |
| Gasunie, DRC West project page | consulted 2026-08-30 | installed 2031–2032 |
The Delta Rhine Corridor is the clearest documented case of infrastructure timing, because the Dutch government explains itself in writing to parliament.
The June 2024 letter records that the earlier assumption had been that the corridor's pipelines, hydrogen included, would be ready for use at the end of 2028, and states that the planning of the first modalities shifts by four years against the previously communicated schedule — putting the hydrogen connection at 2032, with the choice of an integrated spatial procedure given as the cause.[9]
Two points of precision that matter, and that a headline would lose.
First, 2028 was itself already a revision, set in a letter of 5 October 2023. What the pre-October-2023 commitment was is not recoverable from these documents, so "delayed from 2028 to 2032" is accurate against the October 2023 baseline and not against the project's original one.
Second, the December 2024 scope decision put the hydrogen pipeline to Boxtel at 2031–2032 and removed ammonia and the direct-current cables from the corridor entirely.[10] The corridor that is now planned is a smaller thing than the corridor that was announced.
And Gasunie's current public wording is that the hydrogen and CO₂ pipelines are expected to be installed in the DRC West section between 2031 and 2032.[11] Installed is not in service, and no in-service date is published. A project planning to sell into that corridor should not put an operating date in its model that its own infrastructure provider has declined to give.
What has actually been committed
The IEA's measurement of the pipeline build is short:[5]
Around 37 000 km of hydrogen pipelines have been announced to 2035, but less than 6% have reached final investment decision (FID).
What to do with this before your next transport assumption
- Write the load factor next to the transport cost. If the model carries €0.15/kg, it is carrying 5,000 hours a year. Make that assumption visible where a reviewer can argue with it.
- Check the vintage of every infrastructure cost. The standard figure is from April 2022 and the input indices behind it have moved by roughly half. Ask when a number was last computed, not when the deck was made.
- Name the steps your specific route incurs. Liquefaction, synthesis and cracking are separate penalties on separate routes. Ammonia sold as ammonia never pays the cracking penalty; hydrogen delivered pure always does.
- Treat cracking as first-of-a-kind. The largest operating unit is a 30 t/day pilot and the licensor says TRL 6-7. A model that assumes a mature reconversion cost at 5,000 t/day is pricing a plant that nobody has built.
- Take the infrastructure provider's own wording for the date. "Installed 2031–2032" is what Gasunie says, and it is deliberately not "in service". A schedule built on the more optimistic reading is not built on the source.
- Ask what happens if the line is late. Fewer than 6% of announced kilometres had reached FID. The project's contingency for arriving before its evacuation route is a real number, and for most projects it is not in the model.
None of this argues that hydrogen cannot be moved. It argues that the cost of moving it is not a constant anyone has published recently, that the energy penalties are published and specific to a route, and that one link in the ammonia chain does not yet exist at the scale the chain assumes.