Special Focus: Hydrogen Infrastructure Development

 

J. JENS, A. WANG, K. LEUN, D. PETERS and M. BUSEMAN, Guidhouse, Utrecht, Netherlands

In 2020, eleven gas infrastructure companies published a vision of a European Hydrogen Backbone (EHB), a dedicated H₂ pipeline transport network spanning 10 European countries. That report sparked a debate on the role that a H₂ network can play in the future European energy system. The role of H₂ in enabling climate neutrality is widely acknowledged, as is the need for H₂ pipeline transport. This article presents an updated and extended EHB vision, now involving 23 gas infrastructure companies from 21 countries. It presents updated H₂ infrastructure maps for 2030, 2035 and 2040, with a dedicated H₂ pipeline transport network largely based on repurposed existing gas infrastructure.

By 2030, the EHB could consist of an initial 11,600-km pipeline network, connecting emerging H₂ valleys. The H₂ infrastructure can then grow to become a pan-European network, with a length of 39,700 km by 2040 (FIG. 1). Further network development can be expected after 2040. In addition, the maps show possible additional routes that could emerge, including potential offshore interconnectors and pipelines in regions outside the area where the EHB members are active. The proposed expanded pan-European H₂ backbone can further support the integration of renewable and clean energy sources in regions that were not yet included in the initial EHB plan, as published in 2020. These include Finland, Estonia, large parts of central and eastern Europe, Greece, Ireland, and the UK. 

The EHB creates an opportunity to accelerate decarbonization of the energy and industrial sectors, while ensuring energy system resilience, increased energy independence and security of supply across Europe. Such a vision can be achieved in a cost-effective manner, but it requires close collaboration between EU member states and neighboring countries and a stable, supportive and adaptive regulatory framework. 

In addition to maps showing the possible future topology of H₂ infrastructure, this article also provides an updated breakdown of repurposed vs. new pipelines and estimates of total investment costs up to 2040. As proposed in this article, the 39,700-km EHB for 2040 requires an estimated total investment of €43 B–€81 B ($47 B–$88.5 B), based on using 69% of repurposed natural gas pipelines and 31% new pipeline stretches. This cost is relatively limited in the overall context of the European energy transition. 

The investment per km of pipeline is lower vs. the network investment costs as estimated in the initial EHB plan. While the initial plan only included cost estimates for pipelines with a diameter of 48 in., this update considers that a large part of today’s natural gas infrastructure and of tomorrow’s H₂ infrastructure consists of smaller 24-in. or 36-in. pipelines. Smaller pipelines are cheaper to repurpose, leading to lower total investment costs. However, the operating costs to transport H₂ over 1,000 km are higher for smaller diameter pipelines vs. bigger diameter pipelines, which raises the levelized transportation costs for the entire EHB to €0.11/kg–€0.21/kg ($0.12/kg–$.023/kg) of H₂. This is slightly higher than 2020’s estimate of €0.09–€0.17 ($0.10–$0.19) but confirms that the EHB is an attractive and cost-effective option for long-distance transportation of H₂, considering an estimated future production cost of €1/kg–€2/kg ($1.09/kg–$2.19/kg) of H₂. 

The proposed infrastructure pathway up to 2040 shows the vision of 23 European gas transmission system operators (TSOs), based on national analyses of availability of existing natural gas infrastructure, future natural gas market developments and future H₂ market developments. Nonetheless, it is important to note that the eventual infrastructure solution will be highly dependent on future supply and demand dynamics of the integrated energy system, including natural gas, H₂, electricity and heat. The real development of H₂ supply and demand and the increasing integration of the energy system may lead to alternative or additional routes vs. the ones described in this article, and the timeline of some of the 2030, 2035 and 2040 proposed routes may be shifted forward or backward in time.

FIG. 1. A mature EHB can be created by 2040.

EHB initiative. The EHB initiative is a group of European gas TSOs that have drafted a proposal for a dedicated H₂ pipeline infrastructure, to a large extent based on repurposed natural gas pipelines. The initiative published a vision paper in July 2020, with maps covering nine EU member states plus Switzerland, home to the eleven TSOs participating at that time. Since then, the EHB initiative has grown to 23 European gas TSOs, with gas networks covering 19 EU member states plus the UK and Switzerland. This article contains a geographically extended vision for a dedicated H₂ infrastructure stretching across these 21 European countries. 

This updated EHB represents a vision of the growing initiative, with extended H₂ infrastructure maps for 2030, 2035 and 2040. As in the last report, this article includes the locations of possible H₂ storage locations. The amount of storage that would be required in the future depends on several factors and is not further analyzed in this article. Neither does this work analyze the cost of H₂ storage. The suggested pathway for the creation of dedicated H₂ backbone infrastructure is informed by studies¹ commissioned by the Gas for Climate consortium in 2019 and 2020, which showed a large future role for H₂ in a decarbonized European energy system and a gradually declining role for natural gas, partially replaced by biomethane. 

Natural gas remains important to ensure security of supply during the 2020s and 2030s, yet increasingly, gas infrastructure could be freed-up for the transportation of H₂ as over time, H₂ will become a competitive commodity and energy carrier with a key role in the future energy system. Based on these insights, the EHB initiative has created a possible and reasonable scenario on how H₂ infrastructure in Europe may be created that would be technically viable and achievable. The EHB vision is based on the aforementioned Gas for Climate studies, national H₂ strategies and planning processes, as well as an evaluation of announced projects on H₂ supply and demand across Europe, partly through a series of H₂ supply chain stakeholder interviews. 

The EHB vision starts from the current status quo yet assumes a high ambition level for future climate change policies. This article presents a vision rather than a final proposal based on detailed network planning. The timelines for the scale up of H₂ can vary by country, reflecting national energy policy discussions and the status of H₂ investment projects. Therefore, while for some countries more detailed information on planned H₂ infrastructure is already available, this information is not yet available in other countries. On certain routes, natural gas and H₂ may compete for existing pipeline infrastructure. Across Europe, the speed with which dedicated H₂ transport infrastructure can be created depends on market conditions for natural gas and H₂, as well as political support to stimulate H₂ production and demand and regulatory frameworks for H₂ transport. 

Modeling of H₂ and natural gas flows would provide further insights on whether and by when specific gas pipeline stretches would become available for H₂ transport and investments in H₂ infrastructure would be desirable. This is out of scope of the present work. 

The gradual creation of a dedicated H₂ infrastructure. The EHB vision published in 2020² showed that by 2030, separated H₂ networks can develop, consisting mainly of repurposed existing natural gas pipelines. These initial stretches include the proposed Dutch and German national backbones, with additional sections in Belgium and France. H2 networks were also expected to emerge in Denmark, Italy, Spain, Sweden, France and Germany. The updated EHB shows that additional repurposed stretches are expected to emerge by 2030 in Hungary and the UK, with new stretches emerging in Finland. In this updated vision, some of the countries already depicted in the previous report show an accelerated deployment of their H₂ networks. For 2030, this holds for Sweden, France and Italy. Some stretches of the network are now envisioned to emerge already by 2030, representing updated insights. 

In Hungary, the emergence of dedicated H₂ pipelines by 2030 is attributable to rapidly changing natural gas flows, growing H₂ demand in the region and proximity to abundant renewable energy sources. The changing natural gas flows are due to the new LNG terminal in Croatia, new pipeline connections in the region and a changing gas market. Simultaneously, H₂ demand in the region is expected to ramp up. A dedicated H₂ infrastructure connecting the region’s customers to potential green H₂ supply regions (Ukraine and southern Hungary) will be beneficial for the energy system at large. 

In the UK, H₂ could contribute significantly to meeting climate targets. By 2030, four of the country’s five major industrial clusters could be connected through the phased repurposing of existing gas pipelines to form an initial H₂ backbone. Due to the sensitivities around industrial cluster developments, National Grid Gas does not hold any views on the phased sequencing of which industrial clusters in the UK are likely to connect first as it relates to this study. 

In Finland, the H₂ network could develop near the first H₂ valleys in the south, southwest and northwest. Here, significant use of H₂ in industry is envisioned in low-carbon fuel production, chemicals, steel and mining, while also the H₂ network develops along the west coast, which has a large share of the onshore wind potential. Additionally, the H₂ production potential is enhanced by land and water availability, while the recovery of waste heat from electrolyzers could be a potential solution to decarbonize district heating, which is widely used in Finland. 

In Italy, the use and production of H₂ is expected to increase—the Italian Hydrogen Strategy guidelines published in 2020. Domestic production will ramp up, and growing demand also creates the possibility of green H₂ imports from North Africa as early as 2030—subject to market conditions. This possible import could be enabled by repurposing given there are five parallel pipelines between Tunisia and Italy. 

Growing networks by 2035 covers more countries and enables imports. Between 2030 and 2035, the EHB will continue to grow, covering more regions and developing new interconnections across EU member states. The increase in dedicated H₂ pipeline transport reflects the urgency to mitigate climate change and the opportunity for cost-effective decarbonization. A rapidly increasing number of H₂ projects are expected to receive public support. Industries will require access to a liquid, mature and cross-border European H₂ market, enabled by a growing H₂ backbone. Pipeline transport will be valuable to connect regions with abundant solar photovoltaic (PV) and wind potential with energy demand centers, including areas which are out of reach for power transmission infrastructure. Whereas initially the H₂ backbone predominantly serves industrial H₂ demand, studies—including the Gas for Climate Gas Decarbonization Pathways 2020–2050 study—show that during the 2030s, H₂ will become a significant energy vector in other sectors, including heavy transport, and electricity production and storage, thereby complementing the electricity grid to integrate large volumes of renewables in the energy system. 

In central and eastern Europe, in addition to what was presented in the 2020 EHB study, by 2035, an import route from Ukraine to the EU could emerge, passing through the networks in Slovakia and the Czech Republic into Germany. This transit route consists of large diameter pipelines that can be repurposed. Ukraine has high land availability and good onshore and offshore wind and solar PV resources. Combinations of offshore and onshore wind plus solar PV can reach high capacity factors, thus ensuring a high utilization of electrolyzers and pipelines, with limited storage. 

Through Spain and France, a corridor towards Germany could emerge by 2035. This route could connect H₂ demand clusters in the north of Europe with sources in the Iberian Peninsula or even North Africa. This enables these intermittent renewable energy sources across Europe to complement one another, while also providing connections to storage options. This further enables the transport of large quantities of H₂ to facilitate a liquid, cross-border H₂ market. 

Hydrogen Europe’s 2x40 GW Initiative³ has called for 24 GW of electrolyzer capacity in North Africa and 8 GW in Ukraine to be developed by 2030 for exports to Europe. Increased collaboration with those countries, as priority partners, was also specifically identified in the EU’s Hydrogen Strategy.⁴ The corridors connecting regions with abundant renewable energy resources would not only serve for H₂ imports, but also enhance the integrated energy system by connecting diverse renewable sources, such as offshore wind in the north and solar PV in the south. 

In many parts of Europe, gas pipelines can be repurposed to H₂ in an affordable manner. However, in Sweden, Finland and the Baltic states, little gas infrastructure exists currently. A significant new H₂ infrastructure is proposed for these countries, which reflects the ambitious plans to use H₂ in heavy industry in Sweden and Finland. In addition, development of this H₂ network can enable more extensive utilization of clean energy sources and provide important connections between H₂ production and demand in the EU. The network will also support the increased need to balance the future decarbonized energy system. The possible nuclear phase out in Sweden and ambitious national targets to reach climate neutrality by 2045 in Sweden and already by 2035 in Finland require a massive scaleup of variable renewable electricity. Because energy demand is centered in the southern parts of Finland and Sweden, large amounts of energy would need to be transported from north to south. In combination with electricity transmission, H₂ pipelines can provide this energy transport cost effectively. Moreover, next to transporting energy from north to south, H₂ from the Nordics could eventually also be exported into the rest of Europe using the H₂ infrastructure and interconnections. This development would benefit from excellent onshore wind conditions along the coast of the Gulf of Bothnia and from the Baltic sea offshore wind potential. Land and water availability will enable significant development of onshore wind projects in these countries. 

In the Baltic Sea, in the 2030s, the deployment of offshore wind may already reach a significant share of its 93 GW potential,⁵ which will create a need for green H₂ to integrate and store the large amounts of intermittent wind energy. In the three Baltic states, this would create an oversupply of renewable energy, especially during windy periods. For example, in Estonia, renewable energy production during windy periods could reach four times its projected energy demand. By connecting Baltic energy markets with the rest of Europe, H₂ could be exported to Central and Eastern Europe. The Baltic sea region and offshore wind also play important roles in Germany’s H₂ strategy.⁶ 

In the UK, all five industrial clusters could be connected by 2035, resulting in a matured national backbone. In Ireland, a H₂ valley could emerge in the south around the coastal city of Cork, where H₂ could also be imported by ship. 

By 2035, the H₂ network development would allow for the route from Italy, and beyond that North Africa, to expand its reach all the way into northwestern and southeastern Europe. For the latter, a new interconnection from Italy to Slovenia would be used, while Hungary’s network will enable transport further into southeast Europe. Possible imports into Germany are enabled by the repurposed interconnection between Italy and Austria and large diameter repurposed pipelines through Austria, Slovakia and the Czech Republic. Slovakia and the Czech Republic could become an important H₂ hub as H₂ from the north, south and east could flow through the country. The repurposing could solely happen if natural gas flows were to drop significantly, freeing up one of the parallel lines across Italy, Austria, Slovakia and Czech Republic, while still allowing natural gas transport over this route to the extent needed. 

The situation in Germany shows a much more dynamic picture in 2035 compared to the 2020 EHB paper. As natural gas and H₂ may very well be competing for the same pipeline infrastructure, it is unclear whether some of the pipelines will be converted to H₂. An example is the newly suggested route connecting the Ruhrgebiet/Cologne area to the southern parts of Germany. Whether all suggested pipelines will be converted to H₂ or remain natural gas pipelines largely depends on political support for the scaleup of H₂ and the general market developments of H₂ and natural gas respectively. 

Mature infrastructure stretching towards all directions by 2040. By 2040, a pan-European dedicated H₂ transport infrastructure can be envisaged with a total length of around 39,700 km, consisting of 69% repurposed existing infrastructure and 31% of new H₂ pipelines. 

As shown in FIG. 1, the network could stretch from Ireland to Hungary and from Spain to the Nordic countries, connecting different regions with different renewable energy production profiles, providing a cost-effective way to transport large amounts of renewable energy to demand centers and connections to regions with storage capacity. The network would also enable pipeline imports from Europe’s eastern and southern neighbors, as well as imports of liquid H₂ from other continents via Europe’s main harbors. This would provide security of supply and enable the creation of a liquid, European market for H₂. 

By 2040, two additional interconnections between Spain and France can increase the security of supply and flexibility in the large, expected flows of H₂ from Spain and possibly North Africa into the rest of Europe. 

In the North Sea, approximately 180 GW of offshore wind power capacity can be installed by 2050. Model studies⁷ have shown that its integration in the northwest European energy system would require a smart combination of electricity and H₂ infrastructure, making use of 80 GW–90 GW of electrolyzers in coastal regions. Electricity and gas TSOs in Denmark, Germany and the Netherlands are already actively collaborating on planning a hub-and-spoke offshore network of energy hubs in an internationally coordinated rollout. Several Memorandum of Understandings (MoUs) and Letter of Intents (LoIs) between governments in the region together with potential connections to the UK and Norway, extensive offshore H₂ pipelines and energy hubs acting as an international H₂ network in the North Sea, can be envisioned in the late 2030s, connecting the countries bordering the North Sea. 

Analysis by Energinet confirmed the need for H₂ to integrate large amounts of offshore wind energy by showing that effective utilization of more than 10 GW of additional offshore wind requires up to 5 GW–8 GW of electrolysis by 2035.8 Gasunie Germany confirmed a vision on offshore H₂ production near Helgoland in the North Sea as per 2030. Other plans could not yet be shown on FIG. 1 due to uncertainties about locations and timing. 

New H₂ pipeline stretches in Central, Eastern and Southern Europe by 2040 would enable pan-European energy system integration and decarbonization. It would enable a larger role of renewables in a largely coal-based power mix and enable H₂ supply to decarbonize heavy industry located in central and eastern Europe. 

In Poland, by 2040, a mature H₂ network could emerge, which would enable the integration of large amounts of (offshore) wind energy up north. This energy could then be transported in the form of H₂ to possible industrial demand regions in the south, while storage of the intermittently produced energy would be enabled by a salt cavern near the supply in the north. Additionally, the Baltic gas pipeline from Denmark to Poland could be repurposed to dedicated H₂ transport by 2040, respecting long-term natural gas contracts on this pipeline which run until the end of 2037. 

In Austria, an alternative route to transport H₂ from east to west or vice versa would be available. The additional possibilities would contribute to the decarbonization of industry in Austria and to reach the ambitious 2040 carbon neutrality target set by the Austrian government.

In northwest Europe, the 2040 pan-European network would also connect Ireland with the UK to the rest of the EHB by repurposing one of the interconnectors from the UK to Ireland and by repurposing of the IUK interconnector from Belgium to the UK. In Ireland, a H₂ valley could emerge around Dublin, just south of where the repurposed interconnector from the UK would land. In the UK, all options for converting the existing gas network to H₂ have been shown; however, not all these pipelines will have completed conversion to H₂ within this period.

TABLE 1. Estimated investment and operating cost of the EHB (2040).

Updated cost of an expanded EHB. Total investment costs of the envisaged 2040 EHB are expected to range from €43 B–€81 B ($47 B–$88.5 B), covering the full capital cost of building new H₂ pipelines and repurposing pipelines for the European backbone. The ranges reflect differences in capital cost assumptions, with the greatest uncertainty stemming from compressor costs. Annual operating costs are estimated to be between €1.7 B ($1.86 B) and €3.8 B ($4.15 B) when assuming a load factor of 5,000 hr/yr. Note: Not all these operating costs are additional to current costs of running natural gas infrastructure. For reference, annual operating costs of natural gas infrastructure are around 5% of investment costs. Regarding load factor, this study considers the backbone from an infrastructure investment perspective and does not take a strong stance on the exact level of network utilization. A load factor of 5,000 hr/yr is deemed reasonable, cognizant of the fact this value will change depending on future market developments, which will impact resulting costs accordingly.

An overview of these costs is provided in TABLE 1. Transporting H₂ over 1,000 km along an average stretch of the H₂ backbone, as presented in this report, would cost €0.11/kg–€0.21/kg ($0.12/kg–$.023/kg) of H₂ transported, with €0.16/kg ($0.17/kg) for the central case. This corresponds to €3.3/MWh–€6.3/MWh ($3.61/MWh–$6.89/MWh) of H₂ per 1,000 km, with €4.9/MWh ($5.36/MWh) in the central case. Although marginally higher than 2020’s estimate, this confirms that the EHB is an attractive and cost-effective option for long-distance transportation of H₂, considering an estimated future production cost of €1/kg–€2/kg ($1.09/kg–$2.19/kg) of H₂. 

The updated investment costs shown in TABLE 1 and updated transport costs per kg of H₂ differ from the previous estimate of €27 B–€64 B ($29.5 B–$69.96 B) reported in the 2020 study, with transport costs of €0.09–€0.17 ($0.10–$0.19) to transport a kg of H₂ over 1,000 km. The difference in investment costs and levelized costs vs. the previous EHB report are due to a combination of the following three factors: 

1. The backbone has expanded in length and scope. The updated network covers a total distance of 39,700 km across 21 European countries with highly diverse gas infrastructures, compared to 23,000 km across 10 countries in the previous EHB report.
2. The relative share of repurposed and new pipelines has changed following the geographic expansion of the network. The enlarged network includes 69% repurposed pipelines, while 75% of the previous shorter network consisted of repurposed pipelines. This change is due to country-specific differences in network topology, expected pipeline availability and the creation of new H₂ networks for renewable energy integration in the Nordics, where limited gas infrastructure exists.
3. A more granular assessment of pipeline diameters has been conducted. Pipeline diameters of gas grids across Europe differ in size. The previous study used a simplified assumption that the entire backbone would consist of large 48-in. pipelines. The updated investment costs presented in the current report differentiate between 48-in., 36-in. and 20-in. pipelines (1,200 mm, 900 mm, and 500 mm, respectively). Approximately half of the total network will consist of medium-sized pipelines plus smaller stretches of pipelines with a small diameter. Repurposing or building new smaller sized pipelines imply reduced unit capital costs and lower throughput capacities compared to 48-in. pipelines. The breakdown of the EHB network by pipeline length, diameter and type—repurposed or new—is shown in FIG. 2.

FIG. 2. Breakdown of the EHB network by pipeline length, diameter and share of repurposed vs. new pipelines.

FIG. 2 shows that, based on an analysis of the existing gas network, nearly 90% of the EHB can be expected to consist of medium [28 in.–37 in. (700 mm–950 mm) diameter] and large [> 37 in. (> 950 mm) diameter] pipelines. For simplicity, it is assumed that the share of pipeline diameters for newly built H₂ stretches remains comparable to the current shares in the natural gas network. 

Representative unit capital cost figures for small, medium and large H2 pipelines are summarized in TABLE 2. These figures use 20-in. (~500 mm), 36-in. (~900 mm) and 48-in. (~1,200 mm) as models to represent small, medium and large pipelines, respectively. This is a simplification of reality, given that the actual backbone is made up of a continuous range of pipeline sizes. Additional underlying cost assumptions such as compressor costs, depreciation periods, and operating and maintenance costs are also shown and are consistent with those used in the previous EHB report of July 2020. These cost estimates are based on gas TSOs’ preliminary research and development efforts with regards to H₂ infrastructure. The ranges are determined through comparison with experience investing in and operating existing natural gas networks and based on initial experience in pilot projects. Although some dedicated H₂ components have been tested in pilot projects, no large-scale H₂ infrastructure exists to provide real historical benchmark figures. Equal to the previous results in 2020, these cost estimates are based on running an average single stretch of H₂ pipeline. They do not incorporate a scenario-based simulation of a full-scale network, as is commonly done for network development planning.

TABLE 2. Cost input ranges used for estimating total investment, operating and maintenance costs for H₂ infrastructure. This data was adapted from the original EHB report published in 2020.

The inclusion of sub-48-in. stretches—mainly medium-sized pipelines of around 36 in. in diameter—significantly reduces the overall investment cost vs. a case where all pipelines are assumed to be 48 in. in diameter. At the same time, the levelized cost of transport is somewhat higher for smaller pipelines, which raises the overall levelized cost. As a result, transporting hydrogen over 1,000 km along an average stretch of the H₂ backbone, as presented in this article, would cost €0.11/kg–€0.21/kg ($0.12/kg–$0.23/kg) of H₂ transported with €0.16/kg ($0.17/kg) in the central case. This corresponds to €3.3/MWh–€6.3/MWh ($3.6/MWh–$6.89) of H₂ per 1,000 km, with €4.9/MWh ($5.36/MWh) in the central case.

TABLE 3. Overview of unit capital costs for different pipeline transport scenarios.

This price figure represents a blended average across a wide range of pipeline sizes and types—ranging from repurposed 20-in. pipelines to new 48-in. ones—and reflects their respective distance and capacity-weighted shares within the context of the overall EHB. The blended levelized cost of €0.11/kg–€0.21/kg ($0.12/kg–$.023/kg) per 1,000 km is calculated by multiplying the estimated levelized costs for each pipeline diameter by their respective capacity- and distance-weighted shares (i.e., the relative amount of H₂ transported by that pipeline size across the entire backbone). 

This means that even though smaller pipelines have a higher cost of transport per unit distance, their modest share in terms of length and capacity leads to a modest impact on overall transport costs when considering the pan-European picture.

TABLE 4. Overview of levelized cost of pipeline transport, assuming 5,000 load hr for different scenarios.

The cost ranges reflect uncertainties in the estimate of the cost of the EHB. Depending on circumstances, the costs for individual stretches can be lower or higher than the range indicated. 

Updated costs. The updated cost estimates are the result of a series of hydraulic simulations conducted by gas TSOs. The modeled scenarios cover a range of point-to-point pipeline transport cases with varying input parameters—selected by TSOs—including pipeline diameter, operating pressure and design capacity. Note that these analyses, while thoroughly conducted, are not exhaustive and merely serve as high-level approximations of what would happen in a real network. Regarding inlet (starting) pressure, operating (maximum) pressure and compression requirements to achieve these, there are no standardized rules or benchmarks for these currently. Views on these key parameters differ amongst TSOs and depend on project-specific planning considerations, and pressures may differ from the figures reported in this study. Therefore, given the simplifying assumptions made in the analyses, these results should not be considered as representative of a fully optimized, actual meshed pipeline grid. Key results are summarized in TABLES 3–5.

TABLE 5. Breakdown of estimated lengths by pipeline size and shares of repurposed and new pipelines of the EHB (2040).

As defined in this study, small pipelines make up about 10% of the backbone in terms of length and typically only cover modest distances, up to 200 km, at a time. For this reason, levelized costs are expressed per 1,000 km for medium and large pipelines but per 200 km for small pipelines. In addition, newly built small pipelines would likely only be constructed in niche situations (e.g., where they are needed to connect two existing repurposed natural gas pipelines of the same size).H₂T

LITERATURE CITED

1. Gas for Climate, “Publications,” online: https://gasforclimate2050.eu/publications/ 

2. Wang, A., K. Leun, D. Peters and M. Buseman, “European Hydrogen Backbone: How a dedicated hydrogen infrastructure can be created,” Gas for Climate, July 2020, online: https://gasforclimate2050.eu/wp-content/uploads/2020/07/2020_European-Hydrogen-Backbone_Report.pdf 

3. W. Ad and J. Chatzimarkakis, “Green hydrogen for a European Green Deal: A 2x40 GW Initiative,” Hydrogen Europe, March 2020. 

4. European Commission, “A hydrogen strategy for a climate-neutral Europe,” July 2020, online: https://ec.europa.eu/energy/sites/ener/files/hydrogen_strategy.pdf 

5. Simonelli, F., “Competitiveness of the heating and cooling industry and services—Part 2 of the study on the competitiveness of the renewable energy sector,” European Commission, 2019. 

6. Federal Ministry for Economic Affairs and Energy, “The National Hydrogen Strategy,” German federal government, June 2020, online: https://www.bmwi.de/Redaktion/EN/Publikationen/Energie/the-national-hydrogen-strategy.pdf?__blob=publicationFile&v=6 

7. North Sea Wind Power Hub, “Integration routes North Sea offshore wind 2050,” Navigant, a Guidehouse company, April 2020, online: https://northseawindpowerhub.eu/sites/northseawindpowerhub.eu/files/media/document/NSWPH-Integration-routes-offshore-wind-2050.pdf 

8. Energinet, “System perspectives for the 70% greenhouse gas reduction target and large-scale offshore wind,” online: https://en.energinet.dk/Analysis-and-Research/Analyses/System-perspectives-for-the-70pct-target-and-large-scale-offshore-wind