Here’s our written summary of our panel debate held on 16th June “Hydrogen: Designing the Net Zero Gas System”. With representatives from BASF, SNAM and ELIA to cover consumption, gas and electricity, there were plenty of differences of opinion. For example, with no end in sight for demand for green electricity for the grid, is it efficient to use some of it for hydrogen? Will subsidies for hydrogen skew markets away from industrial electrification? What about alternatives to hydrogen, like ammonia? Should hydrogen be blended, even in the short term? The participants were Jochen Wagner, BASF, Team Lead Energy & Utilities EU / Procurement & Regulatory Affairs; from Europe’s largest Gas TSO, Giulia-Maria Branzi, SNAM, Head of Climate Policies; electricity’s Nicolas Gielis, ELIA, Head of Strategy; Walter Boltz, Senior European Energy Advisor with the discussion moderated by Catherine Galano, Associate Director, Frontier Economics (sponsor). The summary was written by Sara Stefanini.
Hydrogen: Designing the Net Zero Gas System
An online panel event held on 16th June 2021
- Catherine Galano Associate Director, FRONTIER ECONOMICS (moderator)
- Jochen Wagner Team Lead Energy & Utilities EU / Procurement & Regulatory Affairs, BASF
- Giulia-Maria Branzi Head of Climate Policies, SNAM
- Nicolas Gielis Head of Strategy, ELIA
- Walter Boltz Senior Advisor European Energy – Walter Boltz Consulting
The European Union energy system will increasingly turn to clean and renewable electricity and away from fossil fuels as the bloc races to meet its target for net zero emissions by 2050. But clean electricity cannot entirely replace fossil fuels on its own – green forms of gas, or molecules, will still be needed both for energy and for industrial processes, such as chemicals production.
Green hydrogen, produced from clean and renewable energy, has the potential to fill at least some of this demand. But time is short to develop an entirely new hydrogen market, transport network and regulatory framework – which means it will have to evolve in-step with the technologies and solutions.
This requires a flexible, technology-neutral policy framework that does not inadvertently disadvantage viable options, and requires policymakers and industry to use and adapt existing infrastructure and regulations where possible – rather than developing a separate, untested system.
Existing gas infrastructure is expected to be able to carry hydrogen around Europe and from neighbouring regions. It is currently being tested for blends of natural gas and small amounts of hydrogen. But blended hydrogen will have to be used as a transition to pure hydrogen, not an end-goal. Its effect on carbon emissions is limited, and it cannot be used for industrial processes such as chemicals, which use pure hydrogen and pure natural gas.
The creation of a hydrogen market will require greater integration and cooperation between gas and power transmission system operators, but full integration could create more complexities than benefits.
The hydrogen potential
- It could be a very clean form of energy molecules, which will be needed to fully decarbonise the energy sector by 2050.
- Snam is testing hydrogen-gas blends, with 10% hydrogen, and has not found any constraints on storage.
- Guarantees of origin can help develop the hydrogen market, especially by promoting international trade with regions surrounding the EU.
- Pure hydrogen is an essential building block in decarbonising chemicals production.
- The chemicals industry needs both hydrogen and natural gas in pure forms, rather than blended, so is more in favour of dedicated hydrogen infrastructure.
- Separating a gas and hydrogen blend would be costly and waste energy for chemicals companies.
- Snam sees gas-hydrogen blends as a transition towards pure hydrogen networks.
- A lot of industrials are already using hydrogen from fossil fuels. So why not start there, where there is value and huge potential?
- In 2035 – 2045, there will be a lot of excess renewable electricity generated in order to provide baseload electricity. That excess can produce hydrogen.
The hydrogen challenges
- Hydrogen is still nascent and the normal investment cycle and cost of replacing one technology with another would take too long to meet the EU’s climate targets.
- The business case is still unclear, which makes it hard to attract funding.
- There are legal and policy uncertainties, which makes it hard to invest.
- There is a risk the rules are either developed very late, or are cumbersome and impractical and delay the whole process.
- It would be impossible to build a third silo of hydrogen rules and systems, that interacts with other energy siloes, within less than 15-20 years.
- The regulatory framework for gas-hydrogen blending is complicated and would need an EU-wide provision.
- Pure hydrogen has a much higher price than gas, so blending them reduces the value.
- A blend of 20% hydrogen would only reduce emissions by 7%, so may not be worthwhile.
- The challenge with green hydrogen is having access to renewable electricity. Chemicals sites, for example, may not have renewable generation on-site.
- It would help to have regulations on how the benefits of hydrogen can be shared – especially if the costs and benefits fall in different countries.
- Given the urgency and timetable we are not really likely to get the best solution so should be happy to get a workable solution.
Hydrogen infrastructure and transport
- We should use existing know-how and experience from the gas market.
- We could use our mature gas framework, institutions, hubs, transparency rules and internal energy market infrastructure for hydrogen.
- It’s likely we will use less gas and will need to retire some infrastructure, so we need to think about how we do this, who pays, etc.
- It’s much easier to repurpose assets within a fairly identical regulatory system.
- If the hydrogen system is completely separate from natural gas, why would a gas TSO sell a pipeline to a hydrogen TSO for anything below market value?
- We are well advised to use a system that’s similar to the natural gas system, make only necessary adjustments and cover the ramp up with a few years of derogations.
- With a centralised market that leverages existing infrastructure you could exploit existing pipelines and storage assets at the early stage of the hydrogen market’s development.
- It’s important to establish clear regulatory principles for hydrogen infrastructure.
- Subsidies can ensure the financial viability of hydrogen, at least in the beginning.
- The best way to create dedicated hydrogen infrastructure is to repurpose abandoned gas pipelines.
- This requires an integrated grid network development covering hydrogen, electricity and gas.
- Integrating hydrogen, power and gas into one model would increase the complexity of the model for gains that have yet to be proven. The temporality of electricity is different from gas.
Alternatives to hydrogen
- The best way to use renewable energy is in the electricity system. If converted to hydrogen, it should be used as hydrogen.
- Today, half of the world’s hydrogen is used to produce ammonia, so why not ship ammonia directly? Ammonia could provide the necessary molecules too.
- Studies show that imported hydrogen from South America or the Middle East is not the best carrier because of low energy intensity, so it may be better to import methane or ammonia.
- Ammonia sounds appealing technically but is a security and political risk.
- Under 3,000-4,000 km, hydrogen is more convenient to transport along pipelines compared to alternatives including liquid hydrogen.
This is a summary, not a verbatim transcript, of the key points made during the online panel event. FULL VIDEO HERE
Senior Advisor European Energy – Walter Boltz Consulting
WB: We’re starting from a basic fossil gas system, and we are clearly going to become a fully decarbonised energy system in 2050 or around 2050. We want to decarbonise all energy, including natural gas.
The issues are: how to do it, how quickly, and how to ensure we retain a reliable supply of the energy molecules needed for a stable energy system.
We should strive to transition from the current system to a fully decarbonised system as cost efficiently as possible. We should be careful, because policy tends to favour some technologies over others. If these decisions are made before we fully understand the costs and benefits of different technological solutions we might have significant wasted asset values. The push to decarbonise the electricity sector, for example, reduced the asset value of European power stations by around 50% – around €200 billion.
It’s clear that hydrogen is potentially very clean, depending how it’s made. Most believe that between now and 2050 we will need some molecules, not just electricity. The normal investment cycle and normal cost of replacing one technology with another is just too slow to meet the targets. We don’t have 30 years to build up a hydrogen sector that then needs to grow.
There is a lack of available market-ready technologies, although it is improving. We have problems with attracting funding because the business case is still unclear. We have large legal uncertainties. There is debate over how to regulate hydrogen, and that creates uncertainty and makes it even more difficult to find investment.
We are delaying the process, so in the end it will be expensive to reach our targets. There are some moves to put regulations in place, for example requirements for renewable hydrogen. But this limits the possibility for producing green hydrogen.
There is a risk the rules are either developed very late, or are cumbersome and impractical and delay the whole process.
We should try to use existing know-how and experience from the gas market. We have a mature framework, institutions, hubs, transparency rules, and a huge infrastructure that can support the internal energy market for natural gas and could do something similar for hydrogen.
It’s likely we will use less gas and will need to retire some infrastructure, so we need to think about how we do this, who pays, etc. But it’s more important to know what this regulatory framework will look like than it is to get it perfectly right.
Building a third hydrogen silo with rules that have to interact with the other areas would be a formidable task. It would be practically impossible to do it faster than within 15-20 years.
We already have national regulations, hubs, trading rules, access rules for the network. ACER has developed a reasonable decision-making practice after a few hiccups, we have ECJ rulings that we understand. It would be a big challenge to create similar legal certainty for hydrogen.
We should use the existing natural gas system and adjust it where necessary. It’s much easier to repurpose assets within a fairly identical regulatory system. If the hydrogen system is completely separate from natural gas, why would a gas TSO sell a pipeline to a hydrogen TSO for anything below market value? Re-evaluation isn’t a problem if you have the hydrogen system and natural gas infrastructure in one company.
We need to allow a couple years of exemptions and derogations to get the hydrogen market going, but we should be clear about the direction. This would give more certainty. Developing different hydrogen legislation would probably also require three iterations to get it right, and that gets us to about 2045.
We are well advised to use a system that’s similar to the natural gas system, make only necessary adjustments and cover the ramp up with a few years of derogations.
Head of Climate Policies, SNAM
GB: Snam is Europe’s largest gas transport and infrastructure company.
We see hydrogen developing as a centralised market, where you could optimise supply-demand matching at an international level. This means accessing cheap renewable power – in our case we’re thinking about North Africa – as opposed to more costly renewable power production. It also means security of supply and avoiding costs.
If you were to develop a centralised market leveraging existing infrastructure you could exploit existing pipelines and storage assets at the early stage of the hydrogen market’s development.
To ensure our pipelines are fit in the long run, we are testing injections of hydrogen-natural gas mixtures, with 10% hydrogen. We have introduced new international standards for 100% hydrogen-compliant piping and pipelines and are working on compressor stations and underground storage. We have not noticed any major constraints on using a blend in storage.
Guarantees of origin are powerful tools for delivering hydrogen markets and renewables in general. To promote international trade, especially with surrounding regions, it would help if EU-wide guarantees of origin were extended beyond Europe.
It’s important to warrant additionality for hydrogen production in the medium- and long-term, with an opportunity to allow exemptions in the short-run. For production, you could promote a centralised hydrogen market development by, for example, introducing green gas quotas.
Unbundling rules should not rule out economically desirable investment in the hydrogen value chain. The principle should be to ensure a level playing field across Europe.
It’s important to establish clear regulatory principles for hydrogen infrastructure. These regulatory principles need to be fit from the outset.
Subsidies are connected to ensuring the financial viability of hydrogen as a whole. There might be some benefit in envisaging some public funding at least in the beginning. Joint electricity and gas scenarios could help address issues, alongside a consultation process.
A communication from the IPCEI – the European Commission’s strategic forum for Projects of Common European Interest – and a revision from TEN_E – the Trans-European Networks for Energy – go towards ensuring the financial viability of hydrogen infrastructure.
It’s important to foster cooperation with northern Africa and other surrounding regions, so TEN_E requirements must be adapted to foster this.
Team Lead Energy & Utilities EU / Procurement & Regulatory Affairs, BASF
JW: Hydrogen is an essential building block in the chemistry industry. Reducing emissions from today’s production processes will be critical to the transformation of chemicals production. We consume and produce hydrogen and use natural gas.
We need regulation of hydrogen infrastructure that covers non-discriminatory third-party access. At the same time we need to allow exemptions for existing hydrogen infrastructure. The natural gas infrastructure we have today would be a good starting point.
We need both hydrogen and natural gas in pure forms, rather than blended, so are more in favour of dedicated hydrogen infrastructure.
The best way to achieve this dedicated infrastructure is to repurpose abandoned natural gas pipelines. We are asking for access to hydrogen to be technology-neutral, and think an integrated grid network development is necessary covering hydrogen, electricity and gas.
We might also need access to climate neutral gases that are at least connected from physical flows via guarantees of origin or equivalent.
Head of Strategy, ELIA
NG: We as an electrical TSO look at hydrogen from a different perspective. We want to make sure that hydrogen’s role does not hinder other developments, like energy efficiency and electrification. The best way to use renewable energy is in the electricity system. If converted to hydrogen, it should be used as hydrogen. We need to make sure there is no discrimination, that regulation does not influence change in a bad direction.
We have spoken to industrials who say they could electrify more but today it’s cheaper to do it with hydrogen because it’s not taxed and it’s subsidised. Is this the right way? Hydrogen should first start where it is today – a lot of industrials are already using hydrogen from fossil fuels, the potential is huge, so why not start there, where there is value?
We question whether hydrogen will be the carrier we use in the future. Today, half of the hydrogen in the world is used to produce ammonia, so should we ship ammonia directly? Are we rushing to hydrogen when other molecules could be easier to handle?
Integrated system planning should remain within the parameters of TSOs, with higher coordination. But integrating everything in one single model would increase the complexity of the model for gains that have yet to be proven. The temporality of electricity is different from gas. The models are different, the way the systems react is completely different.
Associate Director, FRONTIER ECONOMICS (moderator)
CG: Jochem, are there conditions where you would accept blending as a user?
JW: The chemistry industry uses hydrogen and natural gas as feedstocks. These chemical processes are sensitive. So we can’t directly use a blend, we have to separate them, and that process costs money and is not energy efficient.
GB: We think in general blending could accelerate the hydrogen market’s development, extending it further and helping to reduce the cost associated with the whole value chain. We see it having a role especially in the transition. We see pure hydrogen networks in the future and blending in the transition phase.
CG: Walter, where do you see regulation in this regard?
WB: The approach to blending or not differs in the EU, there are parts of Europe where pipelines can be transitioned to hydrogen and parts where they need to be built. Is it more economic to build a separate pipeline for hydrogen, or to use blending?
The regulatory framework for blending is complicated, so unless we have an EU-wide provision, blending becomes overly complex. It’s primarily a tool to accelerate the transition where the pipeline is not yet available.
NG: We have a hard time understanding why there is so much willingness to blend. Using hydrogen in the existing market would have a higher economical value if you look at the price of hydrogen today versus natural gas, once you blend it it virtually becomes natural gas. You’re destroying value, and I don’t see why. It would also be burned most of the time which is not efficient compared to alternatives.
Technically, without a lot of investments, it would be possible to blend up to 20% of hydrogen in the natural gas mix. But it would only reduce carbon emissions by 7%, so is it worth that?
CG: What are possible no-regrets system integration actions that would help us investigate what hydrogen has to offer while limiting costs?
NG: There is an existing market that consumes a lot of hydrogen – industrial clusters that produce hydrogen on site. We can start with those industrial clusters and have small networks to distribute the hydrogen within those clusters, and then extend it to either electricity or natural gas.
The other important element is to recognise that Europe will probably be short on renewable energy for demand, so we’ll have to import renewable energy. Studies show that imported hydrogen from South America or the Middle East is not the best carrier because of low energy intensity, it may be better to import methane or ammonia for example.
WB: Decarbonising existing hydrogen use in industrial clusters is a good start, but only if there is sufficient green energy, because it needs a lot of energy. We overlook how much energy we consume in the form of gas at the moment.
Any bigger pilots that use excess power and link electricity and gas systems would be good, because that will be the medium- to long-term use of hydrogen. It would help us try out the real costs, etc. It’s likely we will need to import green energy. In the Arab peninsula there are serious plans to offer Europe blue or green hydrogen, maybe methane, and they will be able to beat us on production costs.
Ammonia sounds appealing technically but it can easily become unpopular – once people realise that, for example, Beirut was destroyed from an ammonia explosion. We just need two accidents and ammonia is out in Europe. It would be a political risk.
CG: What is the role for an integrated and centralised system?
GB: I think there should be a discussion on how best to plan the development of the market. As part of the European Hydrogen Backbone Project we found that under 3,000-4,000 km, hydrogen is more convenient to transport by pipeline as opposed to other forms, including liquid hydrogen and ammonia.
JW: We need integrated network development planning, because hydrogen will be the link between natural gas and electricity. The risk is with all the ideas popping up we might get a very stiff and rigid system where we lose flexibility. If one parameter goes in the wrong direction the system crashes.
We are a consumer but also a producer of hydrogen and will continue our own production for security of supply reasons. How do we get the renewable electricity we need to make it green? We may be looking at a lot of cables over the next year, it may not be easy to get access to renewable electricity.
CG: Nicolas, you see limits to what can be done in terms of power and gas system integration. Where do you see actual operational opportunities and how would this optimise the role of hydrogen?
NG: It’s important to be aligned on the scenarios – what are they going to be in the future, how much electricity will be consumed, how much hydrogen will be consumed, and where? Based on that you can plan your system without mixing everything.
How do we integrate district heating in some cities, for example? How do we integrate mobility, with the rise of electric vehicles? This will become a very complex system to run. The modelling today is not giving results that justify the huge complexity of integration.
In the future we might integrate more and more, but up until now gas and electricity TSOs are speaking to eachother, for example when a gas-fired power station needs to be built.
TSOs might give some additional information to the market parties to say where a connection would be best placed for the network.
CG: Walter, any thoughts on what regulation can do to push cross-sector integration?
WB: The least-cost optimisation of everything is highly complex and probably not necessary.
What would be good is to have some regulations on how benefits can be shared between sectors. If you have a large wind farm or PV installation that is only able to produce 100% during certain hours, there are benefits in converting some of this energy into hydrogen and transporting it by hydrogen infrastructure. But the beneficiary is not so clear in this situation.
Sharing the benefits is not straightforward, especially if the benefits and costs are in different countries. This goes to supporting blending as well, because the costs could be in a different place than the benefits, and that can become highly political.
Managing Director at Energy Post (host)
(A poll of the attendees is run online)
MJ: No big surprises in the poll – a similar model to the gas design is the most popular option. More strict regulation is the next preferred. This poll was run before the opening remarks.
Katja Treichel asks: I’m working on a project called Climate Transparency between Indonesia, Japan and South Korea. Japan is looking at the role of ammonia in coal-fired plants. Are there other countries looking at this and what do you think of it?
JW: We are looking at the role of ammonia as a carrier for hydrogen, but not for coal-fired power plants because we only operate gas-fired plants. Ammonia is imported into the EU, but I don’t see there being an ammonia transport pipeline in Europe. I can imagine importing ammonia into the EU and taking the hydrogen out of it.
WB: Arab producers are selling it, Abu Dhabi for example. Coal-fired power plants in Europe are being closed. I cannot imagine a plant in a densely populated area receiving ammonia – it’s a no-go for security reasons.
Michel Belakhovsky asks: Is it realistic to develop hydrogen without nuclear?
WB: The short answer is yes. If you look at long-run simulations for 2035 or 2045, you see an awful lot of excess renewable electricity generated to provide baseload electricity. So we can produce quite a lot of hydrogen from that, we don’t need nuclear from it.
GB: Extending guarantees of origin to areas where producing renewable power is cheaper, like North Africa, is important because it allows you to address that supply issue that Walter talked about.
NG: As a TSO we need to be technology-neutral. But nuclear is not an option at least for Belgium and other countries that have decided to exit nuclear. We should use low-carbon electricity to produce hydrogen if it cannot be used for other electrification purposes.
Neale Neelameggham asks: I am working on a potential project of rapid transition to hydrogen for transportation using waste energy that is flared. With solar power you need 60 KWh per kilogram of hydrogen, whereas BASF’s pyrolysis project takes only about 15 KWh per kg. You can avoid methane flaring from natural gas by producing hydrogen.
JW: Methane pyrolysis is a project still to be developed, it’s not only us looking into it. It’s more energy efficient, but we still require reliable renewable energy, especially at competitive prices. But we are looking to push that technology as well and have it accepted by governments and society.
Arno Driessen asks: Do you have enough raw materials for example to manufacture electrolysers to meet future demand and lower carbon emissions?
NG: What I hear and read is that developments are ongoing to reduce the use of scarce raw materials both in fuel cells and electrolysers. The sector is aware of those problems. I don’t see a lot of issues, but if we don’t have solutions for huge plants by 2050 there could be complications.
WB: Electrolyser technology has not been in high demand until now, and there is work underway to meet growing demand. This is an interim problem that will be solved, it’s not even in the top three or four issues that need to be solved.
CG: Closing remarks from the panelists.
NG: There are still a lot of diverging opinions around hydrogen, like blending and what kind of electricity should be used to fuel electrolysers and produce hydrogen and whether hydrogen should only be produced from electricity. We should be careful not to jump too quickly to the wrong conclusions, knowing all those uncertainties, and start with the no-regret actions like the existing markets, existing users, etc.
JW: It will be a challenging path ahead of us. The chemical industry looks forward to developing a climate-friendly chemistry based on clean hydrogen. We will require large amounts of reliable renewable energy at competitive prices and we will require the rapid creation of efficient regulated infrastructure to enable transport within the EU and beyond.
GB: The role of policy is important in finding the best way to develop the market and follow the cheapest way of developing hydrogen.
WB: We do need a relatively technology-open solution going forward. But given the urgency and timetable we are not really likely to get the best solution so should be happy to get a workable solution. We need to keep speed in mind. Let’s go for the solution that’s likely to work even if it’s not optimal and let’s keep some options open.
More fundamentalist-driven policy steps are being taken and we need to ask policymakers not to choose options too early.
Summary compiled by Sara Stefanini
Produced by Energy Post
J.H. Martin says
The seminar made no mention of the real elephant in the room for owners of long distance gas transmission assets – investment stranding and decommissioning costs. Local production of hydrogen within the DISTRIBUTION network and at industrial points of use is already within investment horizon for both new gas assets and maintenance of existing gas transmission assets. Embedded production of hydrogen by proven thermochemical or electrolytic methods typically at 50 MW Thermal scale using small/micro HTGR reactors constitutes a direct threat. These have inherent safety under the chemical industry definition so can be located close to population centres and industry, including COMAH sites. Unlike cooler legacy nuclear, the HTGR (high temperature gas cooled reactors) produce 750 centigrade heat for direct use or as hydrogen or as storable ammonia/hydrocarbon synfuel. Deployment at a ‘Paris relevant’ scale by factory, not ‘stick built’ methods is credible with technology readiness and manufacturing readiness levels in excess of 5 and prototypes having run reliably for several decades. Thus, the long distance gas pipeline’s bulk energy transport role is typically supplanted using a single 5 tonne road vehicle trip per gas site per annum. Transport of shielded containers of energy-dense uranium oxide, of reused PWR fuel residues or later of thorium and the associated waste away are well established processes. Most HTGR designs have refuelling interventions of between 5 and 10 years at full load output. Commercially, atomic fuel market trading exists together with mature regulatory/safety frameworks. Furthermore, the gas distribution network is now predominantly polypropylene with low working pressures which make hydrogen embrittlement of pipework a manageable issue with long precedent. This systematic approach is already being actively pursued by many advanced countries’ governments, with engagement by industrial energy users, gas supply companies and energy investors. A brief but rapidly ageing late 2020 primer by UK’s National Nuclear Laboratory is the latest in the government series on this subject at https://www.nnl.co.uk/wp-content/uploads/2020/10/Advanced-Nuclear-for-Heat-and-Hydrogen_AN4H_FINAL-FOR-PUBLICATION_October-2020_Version-1.pdf This is important reading for gas transmission company Boards and their shareholders.