Hydrogen rivals oil and gas for storage and hard-to-decarbonise sectors (industry, heavy and long distance transport). But it isn’t all carbon free. “Grey” hydrogen – the cheapest at €1.50/kilo – is made from gas. “Blue” hydrogen depends on the fortunes of carbon capture technology. “Green” hydrogen is CO2 free, but needs further cost reductions in the green electricity used in the electrolysis process. Noé van Hulst, at the Netherland’s Ministry of Economic Affairs & Climate Policy, runs through what countries around the world are doing to accelerate green hydrogen’s growth. And companies too: Sweden’s Vattenfall says it can produce a €20,000 car from CO2-free steel (using green hydrogen) rather than regular steel, adding just €200 to the price.
There is a growing international consensus that clean hydrogen will play a key role in the world’s transition to a sustainable energy future. It is crucial to help reduce carbon emissions from industry and heavy transport, and also to provide long-term energy storage at scale.
Hydrogen is a versatile energy carrier that can be produced from a wide range of sources and used in many ways across the entire energy sector. It could become a game-changer in its low-carbon form, but its widespread adoption faces challenges.
The International Energy Agency is preparing a major new study to assess the state of play for hydrogen, its economics and potential. Due to be published in mid-June, the report will be a key contribution to Japan’s 2019 Presidency of the G20.
Still too expensive
Researchers have found that clean hydrogen still costs too much to enable it to be widely deployed. Prices may not come down sufficiently until the 2030s, according to some estimates. But despite the uncertainty surrounding the future of clean hydrogen, there are promising signs that it could become more affordable sooner than expected.
Where the hydrogen comes from is important. At the moment, it’s mainly produced industrially from natural gas, which generates significant carbon emissions. That type is known as “grey” hydrogen.
A cleaner version is “blue” hydrogen, for which the carbon emissions are captured and stored, or reused. The cleanest one of all is “green” hydrogen, which is generated by renewable energy sources without producing carbon emissions in the first place.
- “grey” hydrogen: produced industrially from natural gas, which generates significant carbon emissions
- “blue” hydrogen: carbon emissions are captured and stored, or reused
- “green” hydrogen: generated using renewable energy sources with no carbon emissions
Grey hydrogen: gas prices, CO2 taxes may make it more costly
At the moment, grey hydrogen is cheaper than the other two. Its price is estimated to be around €1.50 per kilo. The main driver is the price of natural gas, which varies around the world.
Too often, people assume that the price of grey hydrogen will remain at this relatively low level for the foreseeable future. That ignores the IEA’s projection of a structural rise in natural gas prices due to market forces. And more important, it fails to take into account the potential volatility of gas prices, as demonstrated in Europe, where they have become more linked to spot markets.
What’s more, grey hydrogen’s CO2 emissions carry a cost in an increasing number of jurisdictions around the world. In the European Union’s emissions trading system, the price of CO2 is in the range of €20 to €25 per ton.
A growing number of European Union countries want to establish a minimum CO2 price that will gradually increase to around €30 to €40 per ton over the next 10 years. That means the cost of CO2 could eventually add almost €0.50 to the price of a kilo of grey hydrogen in Europe, bringing the total price to around €2.
In an increasingly carbon-constrained world, we should also not lose sight of the diminishing social acceptability of continuing to emit CO2 while producing and using grey hydrogen in industry.
Blue hydrogen can narrow the gap
The price of blue hydrogen is also mainly influenced by natural gas prices. But its second-most important driver is the cost of capturing and reusing or storing the carbon emissions.
Current estimates put the price of carbon capture, utilisation and storage (CCUS) in the range of €50 to €70 per ton of CO2. The price is lower in specific cases like ammonia production .
This puts the current price of blue hydrogen in Europe a bit above the price of grey hydrogen, but that gap will shrink if the price of CO2 emissions increases further in the coming years.
Once the process of CCUS in blue hydrogen plants is scaled up and standardised, the cost is likely to come down.
Innovation should eventually open up more opportunities for the utilisation of CO2 in industry, which may further push down the cost of CCUS. Those developments could bring the price of blue hydrogen closer to that of grey hydrogen sooner than is often assumed.
Green hydrogen’s price depends on renewables
Different factors come into play for the price of green hydrogen, which is estimated to be between €3.50 and €5 per kilo at the moment.
The first one is the cost of electrolysis, the process through which hydrogen is produced from water using renewable energy. Total global electrolysis capacity is limited and costly at the moment. Most industry experts expect that a significant increase of electrolysis capacity will reduce costs by roughly 70% in the next 10 years.
The most critical factor for the cost of green hydrogen, however, is the price of the green electricity used in the electrolysis process.
The cost of generating solar and wind energy has come down spectacularly in the past decade. That should prompt caution about what will happen to the cost of green hydrogen in the future. Similarly to wind and solar, it may come down a lot faster than experts now expect.
In countries and regions blessed with abundant sunshine and wind power – such as the Middle East, North Africa and Latin America – green electricity prices have come down to around 2 euro cents per KWh.
Experts expect them to decrease even more in the near future. Former US Energy Secretary Steven Chu recently suggested the prices could soon go as low as 1.5 US cents (1.3 euro cents) per KWh.
In those countries and regions, there is a real prospect of mass producing green electricity for domestic use – and also green hydrogen for both domestic applications and export markets.
Towards a global clean hydrogen market?
Green hydrogen can in principle be shipped around the world to places that are less well endowed with cheap renewable energy sources.
Japan has several important pilot projects underway – with countries including Australia, Saudi Arabia and Brunei – to determine the best way to transport green or blue hydrogen over large distances by ship.
It is too early to tell how the cost of transport will develop and how fast this global hydrogen market may develop. Depending on technological advancements, a market similar to that of liquefied natural gas may see the light of day in the decades to come.
Green hydrogen for Europe: when?
What does all this mean for the cost of green hydrogen in Europe?
First, that it may indeed take more time for the cost of green hydrogen to come down to levels near those of grey and blue hydrogen. The scale-up of electrolysis needs to drive down the cost. Even more critically, mass production will require large volumes of cheap green electricity.
The projected scale-up in offshore wind production in Northwest Europe is expected to kick in over the next 10 to 15 years. By the early 2030s, mass deployment of green hydrogen may have begun in that part of the world.
Some big industrial players, like Engie, have set an explicit cost target for green hydrogen to reach grid parity with grey hydrogen by 2030. The Japanese government has also formulated stringent cost targets for clean hydrogen by 2040.
Those ambitions are long term, but they don’t preclude significant use of green hydrogen in the next few years. It’s already happening locally across Europe, where on-site wind or solar power units generate green hydrogen for applications in industry, transport or energy storage.
In a number of cases, creative companies have figured out sustainable business cases. Swedish power company Vattenfall has calculated that producing a €20,000 car from CO2-free steel (using green hydrogen) rather than regular steel would add just €200 to the price. That suggests premium markets could be developed for consumers willing to pay 1% to 3% more for products manufactured using green hydrogen.
Danish power company Orsted recently announced that its bid in an offshore wind auction in the Netherlands includes the production of green hydrogen for industrial use. That shows that new business models are being invented as we speak, raising the possibility of positive surprises ahead.
Shaping hydrogen’s future through policies
Energy policy can clearly make a big difference through measures such as minimum CO2 prices. Another important factor is the way in which the authorities can foster the energy transition.
The Dutch government has announced the broadening of its low-carbon program. At the moment, it’s restricted to subsidies for producing renewable energy, but it will soon be expanded to include all possible cost-effective ways to reduce CO2, including CCUS. This will help the market-driven activation of blue hydrogen projects and, depending on how costs evolve, hopefully that of green hydrogen projects in the near future.
France’s hydrogen strategy includes indicative targets for greening the current use of grey hydrogen in industry. The French government has set a target of 10% green hydrogen use in industry for 2022 and 20% to 40% for 2027.
A proposal from some industry players in Germany (Shell, Siemens, Tennet) aims to organise combined auctions of offshore wind fields for electrolysis, which would imply connecting the value chain in one single tender.
Zero emission standards for vehicles are increasingly popular in many cities and countries. They are a powerful driver of clean hydrogen applications in transport, where diesel and petrol are rapidly becoming less acceptable. This may help bring down the cost of electrolysis even faster.
Many current discussions in Europe also involve proposals such as an obligation to blend clean gas (including hydrogen) into the gas grids. This would help kick-start the clean hydrogen market in Europe, even if we begin at low levels.
Other important policy instruments include the doubling of R&D in clean hydrogen, as agreed in the Mission Innovation initiative; removing fossil fuel subsidies; guarantees of origin for blue and green hydrogen; favourable implementation of the European Renewable Energy Directive (REDII); common quality and safety standards; and aligned regulatory approaches on what roles different market participants can play in this new market.
We can expect to hear much more about policies to stimulate the creation of a single clean hydrogen market in Europe in the months to come. The clean hydrogen future has already begun.
Noé van Hulst is the Hydrogen Envoy for the Ministry of Economic Affairs & Climate Policy, The Netherlands
This article was first published by the IEA
Daniel Williams says
Part 1 – Green hydrogen for Industry
Basically, there are a few options to produce green hydrogen at large scale, but this scale will not start to decrease the market share of natural gas imports until at least 2030-2035 (blue hydrogen should be used instead of nat gas before this date).
Green hydrogen should however reduce the market share of oil products within this timeframe, considering the European targets in place for trucks and passenger vehicles (30% and 37.5% respectively by 2030), the amount of fuel cell vehicle manufacturing capacity planned by 2025, and the higher comparative cost of petrol and diesel vs natural gas; where fuel cells are 2-3 times more efficient than IC engines.
Essentially, to produce green hydrogen at very large scale, a cost price for electricity of €30/MWh is required. This is mainly because there is not enough curtailment available to utilise electrolysers at very low load factors, meaning that CapEx is too high – with an average 25% overall cost increase in conversion to gas; 20% of this is electrolyser efficiency and 5% is CapEx (80% electricity/20% CapEx). If the electrolyser is being used only 30% of the time, either the electrolyser needs to come down in price, or long overall lifetimes are required with good financing so that the electrolyser can sit idle.
Curtailment depends on many factors, but is likely to increase as the share of renewable electricity reaches 100%. Germany lost €1 billion to curtailment last year, and a recent DNV GL report put UK curtailment at 30% by 2030, up from 5% in 2016. However, these issues are being tackled, and increased grid interconnections may also make these arguments invalid.
Variable pricing is another way to generate more green hydrogen; and will help to balance the grid with less electricity infrastructure required. However, this will also need considerable CapEx subsidies in order to reduce the cost of electrolysers (via mass manufacture), going from the MW-scale to GW-scale. This should be easily achievable, as mentioned above, although obviously it will require policies at MS level.
Variable pricing means that more renewables can be built, and when there is an oversupply then the cost of electricity is reduced. This will also need either a high carbon price or some other subsidy.
Generating green hydrogen initially using onshore wind can be achieved with an electricity cost of €30/MWh, combined with high efficiency electrolysis (80% efficiency), and (optionally) a carbon price (€45/ton). The carbon price is equal to an additional €0.50 on the price of 1kg of grey hydrogen (usually around €1.50/kg), and this could pay for the underutilised CapEx cost (because you might need double the capacity of electrolysers to take advantage of the relatively short periods of low electricity prices), or it could mean that green hydrogen competes with a lower natural gas price. This is the general route for green hydrogen in industry, in order to compete with conventional (grey) hydrogen, at €1.50/kg [WEC 2019, ‘Hydrogen – Industry as Catalyst’].
Daniel Williams says
Part 2 – Green hydrogen for Transport
The general route for green hydrogen in transport is an electricity price of up to €60/MWh where the hydrogen is produced on-site. To use only renewable electricity (and thus lower-cost electricity), more electrolysis capacity is required. Given that electricity represents 80% of the cost of green hydrogen, a balance has to be found between the cost of electricity and the capital cost of the electrolyser. Other revenue streams are available; for example if the electrolyser is grid-connected; then it may operate in a demand-response role thus reducing costs – or as mentioned utilising variable electricity rates.
However, adding all this up, the Nel commercial brochures makes the clear case that with on-site production, a €5-6/kg cost of hydrogen (dispensed) can be achieved. According to my figures, this is the same cost as diesel or petrol per km, not including taxes and charges.
Including taxes and charges, hydrogen is half the cost per km in comparison with conventional diesel or petrol vehicles in the EU (€0.05-6/km vs €0.10/km).
This makes a very compelling case for fuel cell vehicle owners, if we can be assured that governments do not tax hydrogen to the level that they tax fossil fuels. The domestic nature of production should offset these minor costs to national revenues.
I would recommend reading the article:
“Electricity storage as a matching tool between variable renewable energy and load”,
proposed for publication. Link below:
The transition to low carbon emitting solutions imposes new challenges to the power sector to accommodate a large penetration of intermittent renewables. It goes beyond the cheapest symmetrical reduction of fossil thermal generation that is being avoided. Storage is seen as the solution and also the option for batteries, but using a Discrete Fourier Transform and real hourly data it is shown that storage acts as an integral function, attenuating the “daily” and “weekly” harmonics of the charging / discharging function and leaving the “yearly” cycle as the main component to set the storage capacity needed. Export / import with neighbour systems shall be seen as a competitor with storage, but it poses mutual dependency and shared security issues. The renewable generation cost reduction in the “learning curve”, achieving a levelized cost below the variable cost of a CCGT is a milestone and it allows accepting a certain level of curtailment as an alternative to reduce the investment in storage. Batteries do not solve the long-term storage problem but today its use begins to be competitive in the “daily” cycle, replacing peaking gas plants and reinforcing the concept that the cost of storage can be seen as an equivalent thermal power plant. Better than assuming a fraction of renewable energy curtailment, it might be the development of Power-To-X solutions (hydrogen, synthetic gas, etc.) or even investing in nuclear power plants and limiting intermittent renewables penetration accordingly. Both solutions represent indirect electricity storage – fuel has a low storage cost – and it can solve the renewable surplus seasonal transfer problem, recovering synchronous generators for providing dispatchable flexibility, inertia to the system and serving as backup for periods with low renewable generation.
Daniel Williams says
Hydrogen can be produced for the same cost as electricity, if we impose a 30% curtailment rate, combined with corresponding ‘peak rate’ utilisation of the electrolyser.
So, we have an electricity price of €30/MWh, which is at 50% capacity factor. We curtail 30% of the electricity, and provide it at zero cost to the electrolyser operator. This reduces the need for expensive grid infrastructure. This 30% curtailment can be added to another 30% of the RES output in order to increase the operational hours of the electrolyser. At a RES capacity factor of 50%, this works out as 15% curtailed + 15% peak, so only 30% CF for the electrolyser in total. This means a low electrolyser cost is needed (€300/kW is required). This process obviously adds to the electricity price; but reduces the need for electrical infrastructure. At €30/MWh using half curtailed electricity, a €30/MWh hydrogen price can be achieved. Electricity is then €40/MWh.
Natural gas imports to Europe last year were €9/mmbtu (€30/MWh).
Daniel Williams says
Looking over my figures, hydrogen for €29.7/MWH can be achieved with a RES cost of €40/MWh and a 50% CF.
30% of the RES is curtailed to provide electricity at zero cost. another 30% is charged at peak rate. So this results in 30% utilisation rate of the electrolyser (50% x 60%), which is charged at half the peak rate (€20/MWh). The electricity cost is increased by 30%, but only 1/3rd of the electricity infrastructure is required, thus reducing grid congestion (and the problem of storage).
RES cost: €20/MWh
Hydrogen conversion: €4/MWh (80% eff.)
Electrolyser cost per MWh:
[30% utilisation rate – 50% x 60%
2628 hours x 20 years – 52,560 hours
Electrolyser capex – €300 per kW
€300 / 52,560] = €5.7/MWh