New DNV study analyzes production and export

A new study by the consulting firm DNV investigates the H₂ export potential from Sweden, Finland and the Baltic states as well as alternative transport routes to Germany and Central Europe. The study shows whether there is sufficient potential for the production of hydrogen for export in the Baltic Sea region, how economically this hydrogen can be produced and how the countries in the region can benefit from the development of an H₂ network and the corresponding trade in hydrogen. For the large-scale export of hydrogen, pan-European pipeline systems can play a decisive role, which is why the study also contains a comparative analysis of possible pipeline routes.

For the decarbonization of central industrial sectors in Central Europe and especially in Germany, the procurement of cheap green hydrogen will be an important challenge in the coming years. Especially the steel industry and basic chemicals will be dependent on the availability of cheap hydrogen. The domestic production of hydrogen in this quickly reaches its limits. It is competing with the decarbonization of electricity generation through renewable energies while at the same time increasing electricity demand through the electrification of key economic sectors – for example in transportation – on the other hand, the domestic production costs for hydrogen in Germany are in some cases significantly higher than in other regions of the world.

In view of this, significant quantities of hydrogen will have to be imported. While sea transport is sometimes the only option for long distances, pipeline-based transport is a cost-efficient option for medium distances. Transport via pipelines has the particular advantage that the hydrogen produced is available in pure form and no transformation losses occur, as is the case with tanker transport in the form of ammonia, for example. Strategically, it is also important for the development of H₂ import chains for Europe and Germany to establish stable partnerships that are also resilient in times of crisis, in order to avoid situations similar to the interruption of gas supplies from Russia in the course of the war in Ukraine.

With that, it is in the interests of all parties involved to look around for possible nearby sources of supply within Europe as well. Various pipeline corridors are currently being discussed in this context and are also being funded by the EU as “Projects of Common Interest” (PCI).

In this regard, DNV on behalf of Gascade has investigated the potential of hydrogen sourcing from Sweden, Finland and the Baltic states in recent months. Based on the existing energy policy objectives of the countries mentioned, an estimate was first made of the possible export potential from the Baltic Sea region. Secondly, the costs at which this hydrogen can be provided and which transport routes will be sensible based on the geographical production potential were determined.

The country analyses, which form the basis of the study, present a differentiated picture of the plans of the individual countries in two scenarios. In each of these scenarios, the planned expansion of renewable energies and the domestic demand for electricity and hydrogen are determined. An optimistic scenario for each country assumes an ambitious expansion of renewable energies for most countries using data from the TYNDP 2022 Scenario Report. This expansion will be combined with a correspondingly ambitious expansion of the respective H₂ utilization in accordance with the country’s respective H₂ strategy. The conservative scenario, in contrast, is less ambitious in all components.

The remaining energy volumes in the respective scenario (after deducting domestic demand from electricity production) are earmarked for the export of hydrogen. It should be noted that this energy could also be earmarked for export as electricity via newly built interconnectors. However, this alternative is not considered further in this study. This results in the following overview of the existing export potential in the two scenarios:

The conservative scenario used in the study shows that Finland in particular can achieve a considerable electricity surplus in 2050, which could be used to produce green hydrogen for export. The Swedish electricity surplus, on the other hand, will decrease continuously over the selected period and the country will no longer have a surplus in 2050. This is due to the moderate expansion targets in Sweden and the simultaneous advance of domestic electrification.

Overall, the conservative scenario results in a potential of about 70 TWh_el in 2050 that can be sourced from the region, with Finland being the main source of the surplus. This reported surplus based on the lower ambitions is quite small, mainly because Sweden, due to its own electrification of industry and domestic hydrogen consumption, shows no surplus in 2050. Nevertheless, wind energy makes a significant contribution in the countries: It can be assumed that onshore wind power will be the main source of surplus electricity in the period from 2030 to 2050, accounting for around 40 to 50% (SE) and 70 to 80% (FI) of electricity generation from renewable energy (RE) sources. This is followed by offshore wind power with a share of renewable electricity generation that will increase to 10 to 20% by 2050 (SE) or about 5% in 2030 and 11% in 2050 (FI).

In the optimistic scenario, on the other hand, development in both countries is more balanced. In this scenario, Sweden shows the highest surplus potential in year 2030, which then halves by 2040 due to electrification, but remains stable thereafter. For Finland, an even greater increase is forecast than in the conservative scenario. Over time, the following total potential for surplus electricity for the production of green hydrogen from the region could therefore be achieved: 2030: 16 TWh_el, 2040: 90 TWh_el, 2050: 119 TWh_el.

Also in this scenario, Finland remains the largest surplus electricity producer and would produce around 30 TWh_el more than in the conservative scenario. In addition to this is a small potential from the Baltic countries and Poland.

For the following analysis of the pipeline routes, this analysis was not only carried out at country level for each scenario, but also differentiated at the regional level – the basis for this forms the existing and planned distribution of REs in the individual country regions.

Calculation of the H₂ production costs
The analysis of production costs is important, as the export of hydrogen as a business is then only sensible if the costs are also competitive in comparison to other possible source regions. In this respect, the levelized cost of hydrogen (LCOH) is the commonly used performance indicator. In a second step, the production costs for green hydrogen are therefore calculated for each region. Compared per region are the LCOH for various production technologies for which the respective regional capacity factors are taken as a basis.

For the calculation of the hydrogen production costs (LCOH), two possible concepts are also examined in the study. First, option 1 assumes that the electrolyzer is operated directly coupled with renewable resources to produce green hydrogen. Alternatively, a different approach is analyzed for the region in which the electricity is drawn from the power grid – which from a regulatory point of view, under certain circumstances specified in the EU Delegated Acts, also make the production of green hydrogen possible. In this case, we check whether the feed-in from renewable energies in the areas examined lies above 90%, as required for an exemption from the RED III criteria with regard to points such as PPAs for renewable energies, additionality and temporal correlation, and then evaluate the hydrogen accordingly on the basis of the electricity costs from the grid.

In summary, the results show that the generation costs of the directly coupled concept appear high. They lie, depending on the region, between 6.15 EUR/kg and 18.75 EUR/kg (see Fig. 2). This seems high compared to the generation costs in southern Europe for directly coupled plants, so at these production costs it is questionable whether exports can be established economically.

Fig. 2: Electricity production costs of hydrogen for direct-coupled onshore wind electrolysis in 2030 for all analyzed NUTS2 regions

Due to the very high share of RE in the Scandinavian regions, however, and the equally low specific CO₂ share per kWh (due to the combination of hydropower, nuclear energy and RE), it can be assumed that for the relevant bidding zones in Finland and Sweden the exemptions of the RED III Delegated Act apply, so the electrolyzers can draw energy from the grid. This significantly changes the picture with regard to the LCOH – especially as the electrolyzers can now achieve a much higher number of full load hours and thus reduce the capital costs in relation to the amount of hydrogen generated. In this way, LCOHs between 2.5 EUR/kg and 4.5 EUR/kg are achieved.

As these in turn depend on the electricity costs in the respective country over the time axis, these electricity prices were taken from the DNV electricity price forecast for Finland and Sweden. Due to the increasing electrification in both countries, the demand for electricity will increase between 2030 and 2050 – which will initially lead to rising electricity prices and thus also rising LCOHs. In the long term, however, DNV expects the electricity price to develop moderately, so the LCOH for 2050 is estimated at around 2.5 EUR/kg (see Fig. 3).

Fig. 3: LCOH Sweden and Finland with grid withdrawal 2030 to 2050

As a result of the cost analyses, it was found that, because of the specific system situation, very attractive production costs for hydrogen can be achieved in Scandinavia. This was already evident this year at the pilot auctions of the European Hydrogen Bank.

Export corridors to Central Europe
In the last part of the analysis, on the basis of the regionalized export potential identified, possible export corridors to Central Europe were evaluated. We have based our analysis on the corridors currently described in the network development plans (European Hydrogen Backbone) and compared them with regard to the regionalized export potential from the first part of the study in terms of their costs and capacities as well as their strategic routing. The following figure shows the five variants examined, for each of which an identical starting point in Finland near the city of Turku was chosen for comparison purposes and the determined regionalized export potential is taken as a basis.

Fig. 4: Five analyzed cases for the (simultaneous) use of onshore and offshore pipeline routes

Both routes connect to the planned Finnish onshore hydrogen transport network that will come from the north of Finland.

Onshore route
The onshore route begins with a connection from Turku to Helsinki, where the Gulf of Finland is crossed by an offshore pipeline segment connecting Helsinki with Tallinn. From there, the hydrogen will be transported through Estonia and Latvia via a newly built pipeline until it reaches a 100-kilometer section of a reused natural gas pipeline in Latvia. The total length of the onshore route is around 2,000 km (1,242 mi). For the calculation of the hydrogen transport capacity, the European Hydrogen Backbone Reports make the following assumptions for the various pipeline segments:

• New construction of 36-inch pipelines (50 bar), nominal capacity of 4.7 GW_H2, capacity factor 100%
• Reused 36-inch pipelines (50 bar), nominal capacity of 4.7 GW_H2, capacity factor of 75%
• New construction of 48-inch pipelines (80 bar), nominal capacity of 16.9 GW_H2, capacity factor 75%

Compared to the other pipeline sections, the rededicated sections have a lower operating pressure and therefore a lower transport capacity. These segments therefore represent a bottleneck for transport capacity. Unless booster compressors are used to temporarily increase the flow rate where possible, this restriction determines the transport capacity of the entire route.

This results in a transport capacity of 30.9 TWh_H2/year, based on full utilization within the limits of the capacity factors specified above and the parts of the network with the lowest capacity (75% × 4.7 GW_H2 = 3.6 GW_H2). If the entire route can be expanded to a transport capacity of 4.7 GW_H2 , a total of 41.2 TWh_H2/year can be transported. At the expected capacity factor for Finnish onshore wind energy of 40%, the transport capacity of a 4.7 GW_H2 connection is 16.5 TWh_H2/year.

A comparison with the expected order of magnitude of the surplus from Finland shows that the onshore route can only cover the expected hydrogen transport capacity from the surplus from Finland in the optimistic scenario (8.6 TWh_H2/year) for 2030. After this time, the onshore route alone will no longer be sufficient to provide adequate transport capacities.

After publication of the DNV study, the consortium Nordic-Baltic Hydrogen Corridor announced that it would abandon its original plans to use pipeline sections consisting of reused natural gas pipelines and – for reasons of transport capacity – would try to provide 48-inch new pipelines over the entire land route. This means that the land route will actually have a greater transport capacity than forecast in this study, if the new 48-inch pipelines can be realized.

Offshore route
The offshore route alternatively starts with a connection from Turku to the island Åland. From there, one or more pipelines with a length of around 760 kilometers run through the Baltic Sea to the Danish island Bornholm. From there, one or more pipelines lead to the German mainland. The total length of an individual pipeline route is around 1,000 km (621 mi). The total length, including a double pipeline route, is about 1,900 km. In this regard, the study analyzed the costs for both a single and a double route.

At a maximum operating pressure of 80 bar, due to the pressure losses induced in the pipeline, a hydrogen recompression is required along the 760‑km route from Åland to Bornholm. In this case, the offshore route must connect to the Swedish island Gotland, to carry out recompression there and/or establish a connection to local supply and demand centers.

For calculation of the hydrogen transport capacity, the European Hydrogen Backbone Reports make the following assumptions:

• New construction of 48-inch pipelines (80 bar)
• Nominal capacity of 16.9 GW_H2
• A capacity factor of 75%, which corresponds to an actual capacity of 111.0 TWh_H2/year.
• Assuming a capacity factor of 40% (Finnish onshore wind energy), this corresponds to an actual capacity of 59.2 TWh_H2/year.

Alternatively, the possibility of a single optimized offshore pipeline sized to be able to transport the expected surplus for all scenarios and years examined was investigated. This pipeline also provided for a connection between the island of Bornholm and the Polish coast in the area Niechorze-Pogorzelica, in order to create a connection with the land-based hydrogen network. The optimization correspondingly provides a dimensioning of a single, about 780‑km pipeline such that it can transport 65 TWh_H2/year at a capacity factor of 40% plus X. The aim of the optimization is to ensure that a single pipeline is sufficient to transport the excess hydrogen from Finland in all analyzed scenarios.

Results of the optimization
The calculation was based on the norm ASME B31.12, Option A. This resulted in an operating pressure of 170 bar and a resulting wall thickness of 60.13 mm. This is outside the standardized range of pipeline wall thicknesses available on the market, but is not unprecedented in the industry. For example, the Langeled pipeline, which runs between the UK and Norway, has similar design specifications. The table below summarizes the required specifications.

Tab. 1: Specifications of the 780 km long pipeline from the Åland Islands to Bornholm

Source: DNV

In summary, the offshore route can meet the expected hydrogen transport needs from the surplus from Finland in the following scenarios:

• Single (unoptimized) pipeline (59.2 TWh_H2/year): All scenarios are met except the optimistic scenario 2050 (62.4 TWh_H2/year).
• Dual (unoptimized) pipelines (118.4 TWh_H2/year): All scenarios are fulfilled.
• Single (optimized) pipeline (65.0 TWh_H2/year): All scenarios are fulfilled.

Techno-economic analysis

The results of the various pipeline route options are summarized below:

Tab. 2: Levelized costs of hydrogen transport for the analyzed pipeline routes

• Case 1: Only onshore route: The total investment costs are around 5.8 billion euros, but at 1.37 euros/kg H₂ based on the levelized cost of hydrogen transport, it is the most expensive option.

• Case 2: Only offshore route – single pipeline: The total investment costs are similar to case 1, but the levelized costs of hydrogen transport are much cheaper at 0.40 euros/kg H₂.
• Case 2 (Opt): Only offshore route – single pipeline (optimized): The total investment costs are similar to case 2, but the levelized costs of hydrogen transport are slightly lower at €0.39/kg.
• Case 3: Only offshore route – double pipeline: Levelized cost of €0.40/kg. However, the total investment costs are around €11.8 billion – twice as much as in Case 2.
• Case 4: Onshore route and offshore route – single pipeline: The total investment cost is similar to Case 3, but the weighted average levelized cost is higher at €0.61/kg.

Although offshore pipelines are about 1.5 times more expensive than onshore pipelines of the same diameter, they are, due to the different total transport distance between the onshore and offshore routes (1,000 km or 2,000 km) in combination with the larger overall diameter and pressure (and therefore transport capacity) of the offshore routes, a more cost-effective option for transporting excess hydrogen from Finland to Central Europe. However, from the perspective of diversification and the development of hydrogen production in the Baltic states, an additional onshore route offers greater security of supply.

Conclusions
The option of obtaining hydrogen from the Baltic Sea region is economically and strategically interesting for Central Europe. Low production costs combined with intra-European production can promote the competitiveness of European industry and would make Europe less dependent on imports. For many end applications, the possibility of obtaining pure hydrogen (and not derivatives such as ammonia) is attractive, as it is more efficient and avoids the costs for conversion processes.

A combination of offshore and onshore pipelines can diversify supply, as there is sufficient hydrogen production potential if the potential for excess electricity from renewable energies is used. An optimized offshore pipeline, however, would be the most cost-effective means of transport to Central Europe.

As a result, it can be stated that a strategic dialogue should be initiated between the states bordering the Baltic Sea and the EU countries dependent on hydrogen imports (especially Germany and Poland). The aim should be to develop a common strategy and vision for a hydrogen network in the Baltic Sea region that further develops the previous considerations in the discussion about a European hydrogen backbone and concretizes plans for RE expansion, pipeline planning and industrial utilization. Due to the many aspects that need to be taken into account, a multinational agreement for such hydrogen production and network expansion would be worthwhile.

Authors: Claas Hülsen, Daan Geerdink, Daniel Anton, DNV Energy Systems Germany GmbH, Hamburg