Photovoltaics and hydrogen in the real world

Photovoltaics and hydrogen in the real world

Guest article by Karl-Heinz Remmers, PV pioneer

For a long time the public has held a deep fascination for solar power and hydrogen. Around the world, both of these technologies have been described as great opportunities and the solution to our energy problems. Indeed, hydrogen is regarded within the current public debate as a cure for all ills. What’s the latest on these solutions? Where does the green power they need come from? And how can (green) hydrogen and photovoltaics more rapidly leverage their huge shared potential?


When we started designing and building solar power plants in 1992, the fascination with hydrogen and solar energy was already immense. However, photovoltaic or PV plants were extremely expensive. In Germany they were only bought by enthusiasts, and even these purchases were dependent on (massive) grants. These (lost) grants came and went, just as the new pilot schemes and flagship projects did. The only relatively stable markets to be found globally were in space flight (no concern about cost) and off-grid, where suitable. Grid-connected photovoltaics didn’t make much progress in terms of scaling up production, and therefore the plants remained expensive and practically irrelevant for energy supply purposes.

In 2000 (global PV market then: 200 megawatts), photovoltaics started to evolve into a mass-use technology, a development that was largely down to the huge international boost provided by Germany’s renewable energy law EEG. In 2023, the global market is expected to reach 380 gigawatts of new installations. The electricity generated around the world by this newly installed capacity would be enough to cover Germany’s current electricity demand.

PV plants have the lowest power-generating costs of all new facilities. These costs have fallen by 95 percent since 2000. It is anticipated that the global PV market will grow tenfold by 2035 – accompanied by further efficiency increases and cost reductions. All this has been made possible through the creation of a market in the earlier stages that can also now in Germany generate solar power without the need for any subsidies.

In our view, we don’t yet have a comparable approach to confidently realize those same (necessary) scaling effects in the hydrogen sector in a way that provides planning certainty for industry. That said, there are hydrogen regions, pilot projects and initial marketplaces springing up all over the place and there is a great deal of goodwill within politics and the media. But when it comes to the market for new hydrogen, things quickly become difficult or just downright impossible. It’s no wonder that large off-takers (e.g., steelworks that have started the conversion to hydrogen) as well as small- and medium-size enterprises are hesitant about purchasing hydrogen, if they are indeed interested at all.

Some can’t get sufficient quantities; others don’t want to pay today’s high prices. For the expectation is that hydrogen will get cheaper. Plus, virtually every day that passes there are fantasies of some – unrealistic – hydrogen import. Or of a bridging technology: blue hydrogen with carbon capture and storage. But nobody has yet stuck a price tag on these potential sources.

The massive success of photovoltaics was previously in having solved this chicken-and-the-egg problem through the EEG. Each energy producer (regardless of size) had a guaranteed off-take over the required payback period along with a price guarantee. Electricity buyers, on the other hand, paid the relevant market prices. As the support scheme was highly degressive, the desired cost reduction was taken into account or given a huge push.

These days, this form of support is barely needed, if at all, and in many areas and countries it is now being aligned with market conditions through the process of tendering. Similar systems for ramping up hydrogen are under discussion in the European Union or are being announced in the form of EU tenders. Just as in the solar and wind industries, contracts for difference or CFDs could be introduced for hydrogen with the establishment of hydrogen exchange prices as a reference point.

Why is that a key issue?

Whoever invests in an electrolyzer (together with storage etc.) can be certain that much cheaper and more efficient equipment will be available to purchase in three to five years’ time. Reliability will also have improved. It’s thus foreseeable that both CAPEX and OPEX, or put more simply, the price per kilogram of hydrogen, will decrease massively. Unless there is a guaranteed off-take at the price needed today, the project quickly becomes bankrupt.

By contrast, the hydrogen buyer from a steelworks or indeed from a municipal energy supplier, for example, will surely refuse to sign a long-term hydrogen purchasing agreement right now when it’s clear that prices will fall massively in the coming years. If an attempt is made to get around this, e.g., through “lost” subsidies or one-off grants, there is the possible threat that, after these measures have been applied, bankruptcy will occur or the electrolyzer will be shut down since the support is indeed “lost.”

What’s more, this type of approach has in the past proved to be highly difficult to get right in terms of how the support is structured. But more than anything, it has always been dependent on the particular budgetary situation of the funding organization.

A “hydrogen CFD” or a similar instrument can incentivize a diverse range of players and also encourage rapid market expansion as well as a quicker pace of innovation.

Application assumptions

If 15 years ago hydrogen-driven cars were the only promising technology for real distances over 100 kilometers (60 miles), then the technological evolution of battery storage has now already superseded this, i.e., prior to mass use. And this has happened despite the fact that the development of battery-based vehicles and their batteries is in its infancy.

By as early as 2025, Germany, too, is likely to witness the price of battery electric vehicles dropping below that of their combustion engine counterparts. Whether you like this reality or not, that proverbial ship has already sailed. If you also take a look at the trend for trucks, the race here will likewise go in favor of batteries.

How things will pan out for commercial vehicles or rolling stock remains to be seen. However, all these categories have a powerful competitor in the form of hundreds of millions of new batteries that are coming on the market globally every year. That’s because these batteries also cushion the grids and make “mass charging” possible. And railroad electrification using common overhead wires is also another real rival when it comes to purchasing and operational costs, as a battery or hydrogen train is not an end in itself.

In my opinion it’s important not to hold onto applications that simply have no real chance of making it big, since it just frustrates people when these promised technologies don’t then materialize. What’s more, using hydrogen for heating in ancient condensing boilers is so nonsensical and expensive that the hydrogen sector should, as a matter of urgency, distance itself from the natural gas sector, which has been pushing this very agenda, so that it can maintain its own credibility and, above all, control the narrative around its own technology.

Applications such as the production of hydrogen-based aviation gasoline or marine fuels and all the other fuel applications as well as hydrogen storage applications – an aspect that desperately needs redefining – are such an enormous future market that there is no need to lament it.

Why do hydrogen storage applications need to be redefined?

In the various long-term scenarios presented to governments by research institutes, there isn’t a single scenario which reckons on the already burgeoning wave of millions of (bidirectional) energy stores in vehicles and the already highly cost-effective medium and large decentralized energy stores. From 2024, no solar farm will be built in Germany that doesn’t have its own storage facility to allow power to be sold at night – and that’s without the need for any funding.

Millions of smaller energy stores are being set up too and these are all significantly extending the actual grid options on offer locally. International developments are taking place at a much faster pace than they once did for PV. Battery storage is making solar energy available “during the night” and “bringing wind to windless days” – for a few hours, then days, then weeks. And this mass availability costs just a few euro cent per kilowatt-hour. This will considerably change all previous scenarios outlined for hydrogen’s use as an energy store.

Off-grid also an option

Hydrogen can also be produced off-grid on a gigawatt scale, provided it is possible to transport the product (hydrogen or an e-fuel) reliably and at a reasonable cost. This is an extremely interesting aspect that is achievable all over the world, with differing proportions of solar and wind power (or, where feasible, other renewable sources). These forms of renewable generation complement each other locally and can, with back-up storage, enable very high running times for electrolysis without costly and time-consuming connection to the power grid. Since their end product is not electricity but hydrogen-based substances. Projects along these lines are happening in various countries, and this has become a realistic option for Germany as well.

Distancing from costly “bridging technologies”

There is a serious ongoing discussion within associations and the media about carbon capture and storage, otherwise known as CCS, and its use in Germany as a bridging technology to obtain blue hydrogen from natural gas by the start of the 2030s. In this case, a technology that is still at the prototype stage after decades of political discussion is being pushed onto a totally unfeasible timeline. And that’s without any discussion of the overall costs of such an option, assuming that (at some point) it is indeed available for large-scale deployment.

Ultimately, CCS has been repeatedly sold as an option for coal power plants since the 2000s and has never come to fruition – for cost reasons. Plus, with such ideas, all the problems of security of supply, costs and the finiteness of natural gas still remain. CCS is a dangerous, insubstantial distraction from the long-term and quickly scalable technology pathway of renewable electrolysis in the EU.

Underrated opportunities

Hardly a day goes by when there isn’t a public discussion of all manner of ideas for the hydrogen economy. It almost doesn’t matter where the German Chancellor or the minister is traveling, it’s nearly always about importing hydrogen. And of course it’s hydrogen at a “bargain price,” with a total absence of debate about the costs or prices. It’s already the case today that a veil is drawn over the massive existing political tensions and risks of potential supplier countries. In fact it’s terrifying how little discussion there is in political and media environments about the EU’s own potential and, especially, the cost of hydrogen options. That’s why I want to make a simple “back-of-the-envelope” comparison, taking into consideration hydrogen minimum costs:

If I want to produce hydrogen “in the desert,” I have to…

– pay (higher) costs than in the EU for electrolyzers, plant engineering, security etc.

– desalinate seawater (CAPEX costs and electricity consumption).

– use wind and solar power at a minimum cost of 1.5 euro cent/kWh, with battery stabilization for high electrolyzer utilization levels on top, albeit the prices will generally be above the costs.

– calculate the losses due to waste heat (20 percent to 40 percent of the electricity used) since the thermal energy will not be used in the local climate.

– calculate the expense of equipment such as the compressors for transportation.

– assess the costs of the pipeline or tanker and their losses in operation.

– adopt a calculated risk strategy for unstable regions.

– …

If I want to produce hydrogen in Germany or in the EU, I have to…

– pay lower costs than in the desert for electrolyzers, plant engineering, security etc.

– pay for water.

– use wind and solar power at a cost of 4 to 7 euro cent/kWh, plus a bit more for stabilization, whereby avoided curtailments from the power grid can lower the price.

– transfer waste heat for the purposes of district heating or process heat. Then I would have 20 percent to 40 percent lower electricity costs because this can be sold as heat – or equally “written off.”

– calculate the expense of equipment such as the compressors for transportation.

– ensure direct consumption locally or short tanker/pipeline routes (lower losses and costs).

– dispense with the need for a risk strategy for unstable regions.

– …

Finally, I think it would be necessary to refine the above back-of-the-envelope calculation by inserting real figures that take into account the expected massive decline in cost. First and foremost, this would enable realistic assessments to be made (at last) about what green hydrogen can cost in 2030/2040 and which prices are reached based on it – in the EU and beyond – thus staying well clear of outlandish buzz phrases like “hydrogen is the Champagne of the energy transition” or “hydrogen will make heating affordable.”

Author: Karl-Heinz Remmers

Point Twelve wins startup pitch

Point Twelve wins startup pitch

H2UB brings together fledgling businesses and investors

Startups are a byword for innovation – and for newcomers who use disruptive techniques to bring new products or services to the world. What they all have in common is the need for cash to launch their companies and build up their businesses. But where to source the money in the first place? In this case, investors are not just useful but an essential means of turning ideas into reality. Various agencies and events are on hand to help startups and investors find one another. One such organization is H2UB, which staged the Hydroverse Convention on June 20, 2023, in the German city of Essen.


The location was quite literally colossal: the Colosseum Theater in the Westviertel area of Essen – once an industrial hall used by the company Friedrich Krupp. In attendance was Nordrhein-Westfalen’s economy minister Mona Neubaur along with over 350 investors, developers and decision-makers from the European hydrogen industry.

At the center of the event was a total of 20 startups, twelve of which took part in a pitching competition which entailed briefly presenting their ideas and answering questions posed by a panel of judges. A broad range of companies was represented, from a one-man band to a European bus manufacturer.

Emerging victorious from the male-dominated contest was the only woman who took part: Flore de Durfort (see image). The CEO and co-founder of Point Twelve, she presented her concept with confidence and style, describing how she, along with her business partners, can help companies get their hydrogen products certified quickly and easily in a largely automated process. De Durfort explained to H2-international: “The IoT and SaaS platform offered by Point Twelve makes it possible for manufacturers of energy-intensive products to easily and continuously certify and monetize their production as green. By automating old, manual, opaque and unscalable certification and verification processes, we generate a process time saving of up to 90 percent and create trust in green products.”

She added: “The initial difficulty lies in the certification of sustainable gases and fuels, particularly those produced from green, renewable power and hydrogen. We made a conscious decision to start with hydrogen certification – a key element in industrial decarbonization and where problems around certification and readiness to outsource are at their greatest.”

The Hydroverse Convention was organized by H2UB, an Essen-based company with eight members of staff that is dedicated to fostering links between corporations, universities, research institutes and investors. The company receives support from the economy ministry of Nordrhein-Westfalen as well as from its four shareholders: OGE, RAG-Stiftung, TÜV Süd and the German Aerospace Center.

Author: Sven Geitmann

Green hydrogen for decarbonization

Green hydrogen for decarbonization

Travel report from India by Sven Jösting

The Green Hydrogen in India congress took place in New Delhi on April 18 and 19, 2023. The occasion prompted an invitation for me to travel from Mumbai via Surat to New Delhi and then through Ahmedabad back to Mumbai. Scheduled along the way was a host of individual meetings with key representatives from major Indian corporations, often at their headquarters. These companies have all identified hydrogen as a new field of high growth and already have large amounts of renewable energy available – primarily solar energy – for hydrogen production. Their aim is to export hydrogen by ship in the form of green ammonia.


A number of large Indian corporations have not only already installed up to 5 gigawatts of solar generation but are each increasing their photovoltaic capacity by 1 gigawatt every year. This could result in green ammonia production of around 1 million metric tons annually – colossal amounts and highly ambitious plans. Although India is currently an importer of ammonia as fertilizer, it wants to turn this situation around within a few years. And its goal is not just to become self-sufficient but also to tap into a huge export market for green ammonia and green methanol. The plan is to take a 70:30 approach, i.e., 70 percent of the volume produced for in-country use and 30 percent for export.

President Modi takes on hydrogen

On the eve of the hydrogen congress, President Narendra Modi gave a speech about climate change on the India News television channel. He set out how India intends to tackle the climate crisis through numerous programs and measures. Every individual in India was reportedly called upon to manage the environment and resources wisely.

In January of this year India set in motion a comprehensive hydrogen program. The initiative gives particular weight to solar energy and wind power as the basis for the production of hydrogen. Green ammonia, along with green methanol, is clearly seen as the way to make hydrogen internationally transportable over the long term, an option which will allow India to develop it as an export commodity. However, since India itself has a large appetite for sustainably produced energy with the aim of reducing, and if possible supplanting, the importation of fossil fuels, the percentage of hydrogen exported will be smaller than the amount remaining in the country.

Of course, alongside climate change, there is also the issue of energy security and how technology may potentially be used to tackle these problems. The focus of the congress in New Delhi was purely on hydrogen.

National Green Hydrogen Mission

Launched only in January, India’s hydrogen program – the National Green Hydrogen Mission – is all-encompassing. Every aspect, from production to the many deployment opportunities, is addressed. Additionally, there will be numerous subsidy schemes. Here’s one example: The blending of hydrogen in gas grids is subsidized by the state, in other words the state assumes the transport costs in the pipelines. As the gas grid is currently not used to capacity, this is the perfect opportunity for hydrogen. To date, the proportion of hydrogen that can be injected is up to 18 percent.

Green Hydrogen in India 

India has fully recognized the potential of green hydrogen. The country is working on highly ambitious plans in which companies are expected to be the primary drivers of implementation. The world’s largest energy conglomerate, India’s state-run NTPC, also plays a significant role in this decarbonization process which is being hastened thanks to a large number of individual projects being carried out across the nation.

India wants and needs to move away from oil and gas imports and also to find alternatives for coal so as to ensure energy security as well as tackle the issue of decarbonization. As it stands, the country spends over USD 90 billion buying in fossil-based energy carriers such as oil and gas. In all, 40 percent of its primary energy is imported. On the other hand, India boasts virtually endless potential to produce renewable energy very cheaply, mostly via solar power and increasingly via wind power – and predominantly offshore in the future. India sees itself as a hydrogen front-runner as renewable energy via solar power can be produced locally at highly affordable prices when compared globally.

There is a real eagerness to lay the foundations for large-scale hydrogen production. Rapid approvals procedures will be put in place for projects relating to renewables generation. People are talking about weeks or a few months rather than years like in Germany. Many areas are ideally suited since they are categorized as “wasteland,” meaning land which is not fit, for instance, for growing food or raising cattle.

The government and the responsible ministries are working on accelerating and supporting the ramp-up of the hydrogen economy by simplifying regulatory processes in addition to introducing assistance mechanisms. In this respect, President Modi is putting considerable pressure on local authorities to quickly make this a reality and to constructively support the hydrogen economy. Modi presumes, in a positive sense, that he is taking the right course of action as guided by his entrepreneurial mode of thinking. I’m told that this is something he is renowned for in his country.

Green ammonia: a foreign currency earner

Given that India still imports over 3 million metric tons of ammonia – derived from natural gas – for use as fertilizer, over the coming years it is possible that the many renewable energy resources coupled with future hydrogen production will make the country not just self-sufficient but also an exporter of ammonia. We are talking about 3 to 5 million metric tons of green ammonia per year as early as 2030 as a means of making green hydrogen transportable. A plethora of projects aiming to build ammonia plants are already at the planning and implementation stages. Many initiatives are located close to ports, rendering them ideal from a logistical perspective.

Pioneering conglomerates

The demand for green hydrogen is huge – above all in the chemicals industry, steelmaking and other industrial applications. A proportion of 10 percent is envisaged for the mobility sector, a figure which includes the use of hydrogen in commercial vehicles, on ships and on railroads. Yet the need for hydrogen is also foreseen for automobiles in the medium to long term according to the manager responsible for this area at the Reliance Group, whose major shareholder Ambani plans to invest more than USD 50 billion in hydrogen.

Ultimately, the issue of the day is still decarbonization. And India’s billionaires were well ahead when it came to hydrogen matters. That’s what leading executives at Reliance, Adani and other companies told H2-international when elaborating on their hydrogen plans. For example, Tata launched a hydrogen think tank together with Rand Corp. way back in 2004. Furthermore, the subsidiary Tata Motors set up a joint venture with Cummins Engine which has recently been extended to involve hydrogen technology.

India to keep electrolyzer production at home

However, there is a squeeze on the availability of electrolyzers needed to produce hydrogen. This situation is not just about the energy required by the electrolyzer but the availability of the necessary quantities of components and/or their capacities. Chinese manufacturers still dominate the scene when it comes to alkaline electrolyzers – the most widely adopted form of electrolysis. India’s intention is to set up its own industry, in other words attract foreign manufacturers and make use of their expertise through the construction of production facilities within the country, all of which will be subsidized by means of state-funded programs.

Market leaders in renewables such as Greenko have therefore established partnerships and joint ventures with companies like John Cockerill (electrolyzers) to ensure that they, too, can have sufficient electrolyzer capacity to meet ambitious corporate goals which include the use of hydrogen for ammonia production. Uniper already has an off-take agreement relating to future production quantities.

For companies in Europe, particularly in Germany, this development is creating extremely interesting opportunities not just to buy hydrogen but also to set up production (fuel cells, electrolysis, hydrogen tanks and component parts) through the transfer of technology by means of partnerships and joint ventures in India in a “local-for-local” approach.

On right path to the hydrogen era

India has fully comprehended the potential for producing its own hydrogen and is setting about making this a reality. Of course, this won’t happen overnight since it requires an enormous amount of capital investment and the projects need to meet the criteria for their financing. The high number of personal conversations with top-ranking officials from government and industry as well as delegates from key provinces leads me to the conclusion and the appreciation that India is perfectly positioned in this respect and will become a leading international player.

Increasing energy demand will continue to be met initially by fossil fuels but will be replaced by renewables and hydrogen little by little. India is on the right path to achieving that goal. Its aim is to be energy self-reliant by 2047 and reach net-zero carbon emissions by 2070. Several weeks ago, India became the most populous country on Earth with a total population of 1.4 billion – overtaking China. This means an intense and rapidly growing hunger for energy – but thankfully this energy will be renewably produced in the medium to long term.

I was able to attend this congress as a member of the delegation from the German advisory initiative Lili Navitas (which stands for “green energy”). The organization’s purpose is to connect up German and Indian companies focused on hydrogen and associated production technologies (e.g., electrolysis) and to facilitate connections in order to foster joint projects in both India and Germany. The initiator was Kiran Bhojani who previously worked in a high-level position at E.ON in Germany and has Indian heritage. He considers it his mission to guide India on its journey to becoming a hydrogen society and to support this by providing contacts and encouraging links between companies.

Author: Sven Jösting

Hydrogen could be produced from seawater

Hydrogen could be produced from seawater

Experts work together to learn new insights

Hydrogen is the most abundant element in the universe and is a renewable energy source, so it’s no surprise that people are interested in feasible ways to produce more. A particular area of focus involves creating hydrogen from seawater. Here’s a closer look at recent progress in that area.


Many researchers quickly realize they’re more likely to make meaningful gains by working with other experts with the same focus. That’s the primary concept of a project involving multiple institutions. The goal is to create a prototype that makes hydrogen from low-grade liquids, including seawater and wastewater.

Participants will work toward that goal by relying on experts with knowledge of electrolyzers and membranes. Over the project’s four-year span, researchers hope to find membranes using abundantly available metals like nickel and iron. They also want to find alternatives to options that cause pollution or have persistent adverse effects, making the associated electrolyzers easier to recycle.

Researchers hope to accelerate their prototype-creation process after identifying future options. Ireland’s University of Galway will be the project’s lead institution. However, participating organizations from Israel, Spain and Germany will also be involved.

This project is part of larger European Commission endeavors to find feasible routes toward the increased production of green hydrogen. For example, the recently announced European Hydrogen Bank’s goal is to domestically produce 10 million metric tons of renewable hydrogen by 2030. That amount would be on top of 10 million metric tons sourced from imports.

People could replace hydrogen with fossil fuels if these collective efforts succeed, resulting in cleaner, more environmentally friendly transportation options. Additionally, facilitating hydrogen production could provide the chemical industry with a more sustainable raw material for producing fertilizers, steel and more.

A newly developed electrocatalyst

Many companies are working on achieving net-zero status. However, there’s no single way to do that. One option is to pursue new technologies to reduce greenhouse gas emissions. Researchers also investigate or create pioneering technologies in their quests to get hydrogen from seawater. Electrolysis involves splitting water into hydrogen and oxygen, and improving that process could make hydrogen from seawater more accessible.

Consider how a team from the Texas Center for Superconductivity at the University of Houston (UH) in the United States made a nickel- and iron-based electrocatalyst that interacts with copper cobalt during seawater electrolysis. That achievement could overcome previously identified challenges associated with obtaining hydrogen from seawater. For example, current electrocatalysts used to achieve oxygen evolution reaction (OER) are prohibitively costly.

The researchers determined that the OER electrocatalysts they made were among the best performers of all multimetal candidates. Another exciting revelation is that the associated technology and process could make hydrogen production extremely affordable.

As lead researcher Zhifeng Ren explained, 1 kilogram of hydrogen currently requires about 50 kilowatt-hours of electricity to make. If the rate for grid-sourced power is USD 0.10 per kilowatt-hour, it costs USD 5 per kilogram of hydrogen for the power alone. That’s far too expensive to make the possibility attractive.

However, a feasible workaround identified during this study is to use surplus power produced by wind turbines or solar panels. That approach would make the power cost less than USD 0.01 per kilowatt-hour. Ren clarified that this option only becomes viable if people continue pursuing hydrogen creation methods that rely on green energy. Researchers can apply the things learned now to future developments in this area.

Researchers make improvements

Hydrogen research is moving forward in ways that go beyond seawater. For example, Italy has Europe’s first hydrogen-powered residential building, which doubles as a living lab. A hydrogen fuel cell powered by solar and geothermal sources provides all the facility’s heat and electricity.

However, one of the most appealing things about making hydrogen from seawater is that the liquid is plentiful and easily available. Getting clean power from the liquid becomes a more realistic prospect when scientists develop better ways to split the hydrogen and oxygen in seawater.

A team from Pennsylvania State University in the US built a proof-of-concept seawater electrolyzer that uses an electric current to accomplish the splitting mechanism. It relies on a thin and semipermeable membrane originally utilized to purify water through reverse osmosis.

The researchers experimented with two commercially available reverse-osmosis membranes and discovered one performed well while the other proved unsuccessful. They clarified more work is necessary to pinpoint the difference in results. However, since they measured the amount of energy needed for reactions, the membrane’s deterioration rate and how well it resisted ion movement, the team already had lots of useful data.

In another case, a group at the University of Central Florida, also in the US, made a thin film with nanostructures on its surface. The nanostructures featured nickel selenide with added phosphor and iron. Previous efforts had limited efficacy due to competing reactions.

The researchers confirmed the new method overcame that problem and is a reliable, cost-effective solution. Experiments revealed the innovation remained highly efficient and stable for more than 200 hours. Future work will focus on making the newly developed materials more electrically efficient and searching for new options to commercialize and fund these efforts.

There’s still a long way to go before getting hydrogen from seawater becomes a widespread and often-utilized option. However, the efforts highlighted here and elsewhere show that people worldwide are eager to reach that goal.

Author: Jane Marsh

Feasibility of an offshore H2 backbone

Feasibility of an offshore H2 backbone

DNV study analyzes establishment and costs

The energy transition in Europe can only succeed if CO2-intensive sectors are rapidly decarbonized as well. In this, green hydrogen will very likely play a central role. Because in many energy-intensive applications, there is no other CO2-neutral alternative. The quantities of hydrogen required to achieve climate neutrality are very high for Europe, however. For decarbonization of today’s H2 production in Europe, about 250 TWh of H2 would be needed. In its hydrogen strategy, the EU assumes an availability of 2,250 TWh by 2050.


As the energy crisis in the previous year showed, dependence on imported energy sources is strategically risky. In this respect, larger quantities of hydrogen should be produced in Europe in order to avoid falling into comparable dependencies to that today with fossil energy sources.

In this context, as an independent technological consulting firm in Germany, DNV has investigated for gas grid operators Gascade and Fluxys the extent to which offshore hydrogen production is economically and strategically sensible and how a large-scale integration of offshore electrolysis into a European grid could make a significant contribution to the supply security of Europe.

Offshore wind energy is most economical

The starting point for the investigations is a comparison of five H2 value chains examined with regard to their H2 generation costs. This assumes production in Central Europe with respect to the wind and solar profiles. Compared are the production chains: onshore wind, onshore PV, offshore wind with onshore electrolysis and HVAC (high-voltage alternating current) or HVDC transmission, and offshore wind with offshore electrolysis and pipeline transmission.

The results of the modeling show that the production of hydrogen by offshore wind energy is in principal the most economical. This is particularly due to the high full load hours – about 5,000 – of the electrolyzer that offshore wind can achieve and through which the capital costs in relation to production become most advantageous.

With the use of offshore wind energy, there is still the question of whether electrolysis should rather take place onshore or offshore. This aspect as well is examined in detail in the study. A comparison of the importance of energy transmission costs on total LCOH (levelized cost of hydrogen) between the three options

1) wired HVAC connection with electrolysis onshore and

2) wired HVDC connection with electrolysis onshore versus

3) pipeline-based hydrogen transmission with electrolysis offshore

shows that up to a distance of about 125 km (78 mi) off the coast, HVAC transmission is more cost-effective compared to HVDC transmission. At distances beyond this, however, pipeline connection is more cost-effective, based on total LCOH. Electrolysis for more distant offshore areas should consequently be carried out offshore. For the study, this limit is drawn at 100 km, as a single pipeline can also integrate several offshore wind farms (see yellow-hatched area in Fig. 2).

If land use, as onshore electrolysis takes up significant area, is considered as a further factor, offshore electrolysis has yet another advantage: The already very intensive land use onshore will not be further intensified. The compact design that is possible offshore is significantly more advantageous.

89 gigawatts in the North Sea in planning

In a next step, the study investigates the offshore wind generation potential for areas in the North Sea and Baltic Sea with a distance to shore of more than 100 km (62 mi). Only those areas are taken into account that have so far been designated for wind projects by the respective countries. The corresponding evaluations show that within the 100 km criterion, 89 GWel of offshore wind energy projects in the North Sea are currently for the most part in the early planning phase. There is still far more potential in the surfaces of the North Sea; however, they are not currently designated for use for wind energy.

If the identified wind potential in the North Sea of 89 GW were to be used exclusively for the generation of hydrogen, then this would correspond to an H2 production volume of around 350 TWh per year, or 9 Mio. tonnes annually. Such a quantity would cover 15 to 20 percent of Europe’s hydrogen demand in 2050, depending on the forecast study used as a basis.

In the Baltic Sea, the potential is significantly lower, at least if the 100 km criterion is stringently applied, because of the shorter distances of the stations from the coast. A deep look at the production potential in the Baltic Sea region was not conducted in the study. However, a corresponding offshore wind backbone in the Baltic Sea could also efficiently drive an onshore H2 production in Sweden and Finland with transmission to Central Europe and additionally be combined with a production at sea.

Differences between natural gas and H2 pipelines

Basing upon the results of the economic viability and the possible potentials from the areas, the study next details the possible technical implementation. Here, it is less about the offshore electrolysis itself, but specifically about options to connect offshore hydrogen production to an onshore grid via an offshore pipeline network. For this, numerous issues need to be addressed, in order to create a hydrogen backbone that can be operated safely.

When comparing for example the transport of natural gas, which is common in offshore environments, with the transport of hydrogen, which has not yet been carried out in offshore environments, several aspects must be taken into account. First, natural gas and hydrogen have different energy contents when they are transported through a pipeline. Natural gas consists mainly of methane (CH4) and normally has an energy content – upper calorific value – between 34 and 43 MJ/m³.

Hydrogen, on the other hand, has a much lower volumetric energy content than natural gas of about 12.7 MJ/m³. This means that when hydrogen is transported through a pipeline, a much larger volume of gas is required to transport the same amount of energy in natural gas. Hydrogen, however, is also a much lighter gas than natural gas.

At normal temperature and pressure, for example, a cubic meter of hydrogen has about one-ninth the mass of a cubic meter of natural gas, which results in a much higher flow rate at the same pressure differences. The combination of these two aspects – low calorific value and light weight – has an equalizing effect, so the energy transmission of hydrogen and that of natural gas are nevertheless similar.

Furthermore, hydrogen has a much higher diffusivity in steel than natural gas and therefore promotes the embrittlement of pipelines following cyclic loadings. This effect can be controlled by an avoidance of cyclic loading, using lower quality steels, – which are softer and therefore less susceptible to cracking – and using a thicker pipeline wall. This also generally limits, however, the ability to reuse existing natural gas pipelines for hydrogen transport.

Taking all this into consideration, the study therefore comes to the conclusion that due to its different volumetric, gravimetric and molecular properties, the transport of hydrogen differs greatly from that of natural gas in offshore pipelines. Offshore hydrogen pipelines should therefore fulfill specific design criteria in order to ensure adequate transport capacity and to be able to operate safely and enduringly. On the basis of the analyses carried out, whose key points alone are treated in this article, the authors conclude that a repurposing of existing offshore pipelines is in most cases uneconomical, especially if the pipeline is to be part of an integrated system and connect several wind farms.

High pressure level possible

As a final step, the study details the technical implementation of a hydrogen backbone in the North Sea. Discussed are, among other things, questions regarding pipeline routing and pressure regimes as well as pipeline costs and required storage capacity as a result of fluctuating H2 production. The transport network sketched in the study connects wind farms in the North Sea with onshoring points in six countries bordering the Sea. For the connection, terminal points on the planned onshore backbones in the countries were selected. The network thus formed has a total length of 4,500 km (2,800 mi) and generally has a north-to-south flow direction.

In the study, a complete hydraulic analysis is not performed, but rather a few approximate calculations. In order to, for example, determine the required feed-in pressure for the transport of hydrogen from Norway to Germany, corresponding calculations were carried out for the necessary pipeline sections (see Fig. 3).

The assumed pipe diameter is 48 inches (1,200 mm). With these parameters, the required feed-in pressure was calculated for different capacities of the pipeline. For an H2 capacity of 25 GW connected to this pipeline section, for example, an inlet pressure of 192 bar is calculated. This is a very high pressure level for offshore H2 pipelines.

The DNV joint industry project (JIP) H2Pipe at this time is investigating the design, construction and operation of offshore H2 pipelines with a pressure of up to 250 bar. Although these pipelines are not commercially available yet, DNV and the JIP partner companies see no major technical constraints to the realization of such pipelines. The economic feasibility in terms of material selection for the pipelines and ancillary equipment, however, will have to be demonstrated in the coming years.

In addition to the pipeline system, the storage demand is also analyzed in the study. Connection to sufficient storage capacity is necessary for near-continuous supply over time. On this, the study shows that about 30 percent of the annual production must be stored, as a prerequisite for this H2 supply based on fluctuating renewable energies. The study accordingly assumes a connection to salt cavern storage facilities in northern Germany and the Netherlands.

Cost calculation

The costs for the outlined network were subsequently estimated. For the North Sea, the total length of the planned backbone is 4,200 km (2,600 mi). Assuming a pipe diameter of 36 to 48 inches (910 to 1,200 mm), the price thus lies between 3,000 and 4,500 euros per meter of pipeline.

According to the assumptions made, the additional LCOH for the pipeline system is between 0.13 and 0.20 EUR per kg hydrogen, i.e. 4.0 to 6.6 EUR per MWh. Since the levelized total cost of offshore hydrogen is 3 to 5 EUR per kg, this means an addition of only 2.6 to 6.7 percent, based on direct production costs.

In addition to pipelines, an appropriate compression regime must be considered. The cost of a compressor varies considerably with the size. The maximum capacity of today’s compressors is about 16 MWel (input capacity). Under the assumption of central compressors for a wind farm; an output pressure of the electrolyzers of 30 bar; an input capacity of the hydrogen backbone of 200 bar, and an arrangement of four compressors, each with 50 percent of the total capacity required and 200 percent of the installation costs; the investment amounts to 46 million EUR for a 1‑GWel wind farm and 66 million EUR for a 2‑GWel wind farm. Thus, the additional LCOH is between 0.06 and 0.08 EUR per kg hydrogen, which corresponds in value to 2.0 to 2.7 EUR per MWh. Since the levelized total cost of offshore hydrogen is 3 to 5 EUR per kg, this means an addition of 1.2 to 2.7 percent.

Overall, the cost for the pipeline and compression is around ten percent of the total specific cost of hydrogen. In addition to pipeline and compression costs, the storage must also be considered as a third component to be added to the LCOH. The result is an additional 0.22 to 0.35 EUR per kg H2 for this.

With the determined system components, the investment costs were estimated in the study as 35 to 52 billion euros to build the outlined North Sea hydrogen backbone. In conjunction with the results of the LCOH analysis, hydrogen from North Sea offshore wind farms can be supplied to Central Europe with it at specific costs of about 4.69 to 4.97 EUR per kg in year 2030. From the point of view of the authors, these costs are competitive with the cost for imports.

In order to implement the outlined system, a coordinated and swift action by the coastal nations involved is imperative. Only so can the necessary network and scaling effects be realized, and an offshore backbone contribute to hydrogen supply to Europe by 2050.

Authors: Claas Hülsen, Ton van Wingerden, Daan Geerdink