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Challenges, barriers, and the costs of the EU hydrogen strategy

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On 8 July 2020 the European Commission launched its communications on the EU Energy System Integration Strategy and the EU Hydrogen Strategy.

In a recent webcast, Daria Nochevnik (Founder ECS Consulting), Nienke Homan (Regional Minister for the Province of Groningen, The Netherlands) and Ad van Wij (TU Delft/ Sustainable Energy Entrepreneur) discussed the future of clean and sustainable hydrogen in Europe. The webinar went on the specifically cover their views on the Commission's EU Energy System Integration Strategy, and what makes the Northern Netherlands conducive to the development of a green hydrogen economy.

Unfortunately, we didn't get the opportunity to cover all the topics we wanted to cover, and we spoke with energy policies and market consultant, Andrei Belyi, to examine the EU's hydrogen strategy a bit further.

We spoke with Andrei about the challenges, barriers, and the costs of the EU hydrogen strategy moving forward.

Read the Q&A below.

Q: What are the costs of this strategy? How much of the existing natural gas infrastructure can be repurposed, and how much cost will come from building dedicated hydrogen infrastructure?

Andrei Belyi: In one of his recent articles in La Tribune, Samuele Furfari – who is now Professor in Energy Policy at the University of Brussels – recalls that first discussions about possible hydrogen development occurred back in 1972 when the world was afraid of possible end of oil.

This historical perspective is important because hydrogen has indeed been known as an energy carrier for decades, but it always faced significant challenges for its extensive use in energy sectors.

Now, the EU has made a significant step forward by setting new, ambitious priorities. The new EU strategy implies development of new infrastructures, and the gas industry has already reacted by proposing a road map for hydrogen pipelines in Europe.

At the same time, it is understood that the existing gas infrastructure may not always be suitable as hydrogen is prone to leakage which can be very difficult to detect. There is also concern that the manganese content of the steel used in the gas pipes could promote embrittlement.

Before achieving a pure hydrogen economy, an intermediary solution could be the so-called hydrogen-enriched natural gas (HENG). It consists of blending gas flows with hydrogen, where hydrogen constitutes from 5 to 20% of the flow, depending on safety standards in place.

However, hydrogen in gaseous form has a third of its calorific value compared to methane. In market terms, adding 20% of hydrogen into gas network will lead to a loss of approximately 16% of calorific value per similar supplied volume. In this context, the questions which would naturally follow is how to incentivize gas suppliers and end users to use HENG?

However, HENG is not the final stop of the strategy. The EU has been explicit that green hydrogen will be a priority. And green hydrogen implies more electricity generation in the future. For example, if we look at the European Commission projections published in 2018, the green hydrogen scenario requires an increase of EU electricity demand in final energy consumption from the current 21% to 43% by 2050.

Ultimately, this means an increase of annual power generation by some 1200 TWh - which should be ensured by carbon-neutral energy sources. There are many questions with regards to these ambitious targets in electricity generation.

So, the success of the EU hydrogen strategy will depend on national energy policies involving promotion of carbon-neutral electricity generation. Should member states favour on nuclear electricity for green hydrogen production being a cheaper option but with higher safety risks and low public acceptance? Or can the green hydrogen economy be solely based on intermittent solar and onshore wind?

A recent HSBC report pointed out that offshore wind would be a good option for hydrogen because of good load. However, offshore wind policy represents another challenge for the EU. Despite quite a significant progress in wind energy,  the EU has only little capacity installed – most of which are concentrated in North Sea – as with the UK’s departure from the bloc, the EU loses up to 42% of installed offshore wind capacities.

Q: What does the future gas grid will look like – two separate grids, one for (bio)methane and one for hydrogen, or all hydrogen? Does blending have any role to play?

AB: In a HENG scenario, blending is key and therefore mixing hydrogen with biomethane would be theoretically feasible although mixing the two leads to calorific losses. Up to now, market for biomethane has been outside the pipeline sector, mostly in transport in mixture with compressed natural gas.

In the last few years there has been encouraging growth in the biomethane market, but its market expansion will be eventually restrained by the availability of biodegradable feedstock. However, in many countries, feedstock utilization for biomethane has been underutilized and therefore biomethane has an incremental potential. For example, in Estonia, only 15% of biodegradable feedstock is used, whereas biomethane already represents 40% of gas supplies for the road transport.

The two fuels will compete in the transport sector, since public transport in many countries is now driven on biomethane. In fact, the Netherlands introduced hydrogen buses in the later half of 2019.

Q: What are the challenges and barriers to scaling up hydrogen at the EU level and integrating hydrogen fully into the internal energy market?

AB: The challenge of large-scale hydrogen utilization for energy is the lacking economy of scale and production costs of green hydrogen. Production volumes provide a clear indicator that hydrogen has not been integrated into energy markets at least up to now. Hydrogen is deemed to replace natural gas, but hydrogen production constitutes only 2% of the global natural gas market volumes and therefore economy of scale for hydrogen is still insufficient for European energy needs.

It is worth noting that hydrogen has been mostly produced for fertilizers in agriculture, refining and ammonia production. Hence a competition for hydrogen supply will certainly occur in case of hydrogen-to-energy strategy use.However, the main challenge for scaling up is the cost of carbon-free hydrogen.

Hydrogen production from an electrolysis process - based on renewable energy generation - remains the costliest option, and therefore electrolysis represents less than 1% of the global hydrogen production.

According to various scenarios, including the recent study produced by the International Energy Agency, hydrogen production from electrolysis would range from 2.5 till 4.5 Eur per kg of H2. In terms of energy market price, it gives a range betweenUSD 15 to 38 per mmbtu, whereas costs of the natural gas production are in the range $1-3 per mmbtu, market price on European hubs have rarely been above USD 7 per mmbtu.

Quite a significant difference in the context where the leading EU’s competitors are favouring natural gas as a transition fuel – which also raises an interesting question as to whether the shift to hydrogen would hinder the EU’s industrial competitiveness.

Instead, various methods of hydrogen extraction from natural gas are certainly more cost competitive compare to the green hydrogen. In a recent paper published in Energy Conversion and Management, Sebastian Timmerberg, Martin Kaltschmitt and Matthias Finkbeiner demonstrate that costs of traditional steam methane reforming ranges between 1 and 1.2 EUR per kg of H2, while methane decomposition systems range between 1.6 and 2.2 EUR per kg of H2.

But these methods require carbon capture and storage, and while there are only few active carbon and capture storage in Europe, it seems that, the decarbonisation of hydrogen production in these methods is debated in a context of economic uncertainty.

Q: Do you believe that any issues will arise around guaranteeing that hydrogen has been sourced sustainably?

AB: There are various ways of producing hydrogen, all of them require a process of heat. Therefore, the carbon footprint depends on the sources generating heat.

Scholarly works demonstrate that fossil-based hydrogen production may generate between 0.15 and 0.34 g of CO2 equivalent per kWh - the figures are equivalent for fossil fuels range of calorific values.A lot depends on the technologies used to produce hydrogen - for example, traditional steam methane reforming or processing gas through a plasma process (pyrolysis).

In short, methane decomposition from pyrolysis is deemed to be less carbon-intensive than steam methane reforming where thermal heat is intensively employed. In short, the production costs for less carbon-intensive technologies are always higher.

If methane-produced hydrogen is taken seriously, then to evaluate the overall GHG footprint of the gas industry, we would need to consider the overall emissions in the natural gas chain before it reaches hydrogen production stage.

For example, fugitive and vented methane emissions from production, transportation and distribution. Some recent observations reveal that Europe is the only continent where methane emissions have declined, elsewhere they go up. Thus, the difficulty consists in defining the source of emissions - should it be a country of origin for the natural gas supply, or the company providing supply service?

In fact, a large part of GHG emissions either stems from gas flaring and venting at upstream level or occurs in distribution of natural gas to households in a form of fugitive emissions from poorly maintained pipes, especially in emerging economies. Suppliers of natural gas to hydrogen production would certainly be European supply companies who purchase either pipeline gas or liquefied natural gas (LNG) from third parties. Hence, they are seldom involved in upstream gas flaring and venting, and they rarely provide downstream services to households. Therefore, their individual carbon footprint will not consider the overall picture of GHG footprint in the natural gas industry.

An interesting question which would need to be answered would be, how do you control these emissions on a large scale? As hydrogen is expensive to produce, it is more than likely that the larger players will be control their emissions. Does this mean the smaller players will be indirectly incentivized either to flare their gas or to sell it ineffectively with higher fugitive emissions?

The question now becomes how to incentivize non-EU suppliers to cut their costs? Alternatively, the EU’s efforts in reducing emissions domestically will be counterbalanced by growing emissions in Central Asia, North Africa, Russia or the US. Recent data provided by the World Bank reveal that gas flaring rates have increased over the last decade, which was marked by less attractive oil and gas prices. Thus, a switch to hydrogen economy in Europe – without incentivizing non-EU producers to cut their emissions beyond hydrogen production - may be even counterproductive for the global climate neutrality.

It all means that the External dimension of the EU decarbonisation strategy should play a bigger role in European agenda because most of methane and carbon dioxide emissions in the global natural gas industry occur beyond the EU.

Q: Are there any applications that you think the EU hydrogen strategy neglects or undervalues, for instance heating?

AB: Certainly, the external dimension is an important area where the EU should put more emphasis. One would need to expand upon the overall system of Guarantees of Origin to incentivize non-EU producers to reduce emissions, otherwise the EU hydrogen strategy will give only little effect on global carbon neutrality.

However, your point about heating is a great question indeed. I know the question of heating was raised during a discussion I had with experts from the Lithuanian Energy institute, who emphasized that hydrogen could be produced from electricity surplus in summer, and then used in winter for heating purposes across the Baltic states.

As heat supply is a very important component in in the region, it could offer long-term potential for security of supply. At the same time, we must understand that any energy innovation is not solely about good ideas and feasible technologies.

A key component to success is industrial stakeholders’ willingness to implement ideas, and about states stimulating industries to take the first steps. Probably, national road maps will have to consider analysis of stakeholders’ engagement to match the ambitious targets with realities on the ground, as well as to find right incentives to increase stakeholders’ engagement.

Interested in learning more about hydrogen’s role in a sustainable future? Join us at Energy Transition World Forum (ETWF). Find out more here.


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