Is there a “first mover advantage” – or not – for an investor in the new hydrogen economy? Michiel Korthals Altes offers a series of “tests” of investment decisions based on the following criteria: economics, climate efficiency, system optimum, price stability, regulation, technology, now and in the future. He concludes that until the sector reaches maturity, conversion inefficiencies make the production of hydrogen a poor choice for most applications. It’s only when the grid is approaching 100% clean renewable generation that making hydrogen makes sense, and we are nowhere near that now. It’s better – both in terms of prices and emissions – that clean generation is used for normal grid uses, e-mobility and heating. If regulators come to the same conclusion, it surely puts a limit on how much support to early hydrogen they can give. In the long term, hydrogen is expected to play an important role, but Altes’ analysis concludes there are big questions over the benefits to early investors.

The sense of urgency prevailing around the developments of production and consumption of hydrogen raises the question whether there is a “first mover advantage” for investors.

The answer is given by testing investment decision according to following criteria: economics, climate efficiency, system optimum, price stability, regulation, technology, now and in the future.

Economics test:

The marginal cost of “green H2” is equal to 1.5 times the cost of electricity. Indeed, as efficiency of the conversion is assumed at 70%, it takes 1.5MWh power to produce 1MWh of H2.

The marginal cost of power is 2 times the cost of gas, considering that gas provides the marginal production. Indeed, as the efficiency of conversion is assumed at 50%, it takes 2MWh to produce 1MWh of power.

Consequently, the marginal cost of “green H2” cannot be lower than 3 times the cost of gas. If its cost were lower, the input power must be below the market value, which is a huge opportunity cost.

The marginal cost of “grey H2” is 1.5 times the cost of gas.

As long as the power market is marginally fed by fossil power, the green H2 will be at least twice as expensive (and CO2 emitting) as grey H2.

Conversely, when the power market is saturated with renewables, the spot market power price falls close to zero. Then green H2 costs drop to the cost of amortisation and maintenance of electrolysers.

Climate test:

For “green H2”, switching on an electrolyser increases the output and emissions of gas or coal plant, to the exception of the few hours a year of excess renewables on the grid. For 1MWh of H2 (=25kg of H2), this results in direct emission of 600kg/MWh (marginal power production on gas) to 1.5kg/MWh (marginal power production on coal).

For “grey H2”, the CO2 emission are around 300kg/MWh of H2.

To pass the climate test, “green H2” should only be produced during the few hours a year that fossil power production is reduced to zero by excess renewables. The amount of “green hours” do not represent more than 5% per year currently.

Question: are the amount of “green hours” increasing sufficiently in the coming year to warrant a business case for electrolysers? Current trends, such as reopening and maintaining coal plants suggest the contrary.

System optimum:

Considering the shortage of green power demonstrated by the ongoing fossil power production, how should green power be allocated to maximise global (and not individual) emission reduction? Let’s rank the emission reduction potential of one renewable MWh according to its usage and the prevailing alternatives:

• Electrical grid: the alternative is gas or coal (400kg to 1tCO2/MWh).
• Currently, European countries are accepting the running of marginal production on gas or coal, which means that Europeans consider their grid consumption to be worth such emissions.
• E-mobility: the alternative is gasoline (750kg/MWh).
• A thermal vehicle is considered 3 times less energy efficient than an electrical vehicle, so one 1MWh electrical transportation saves 3MWh thermal transportation (assuming gasoline emits 250kg/MWh)
• Heat pump heating: the alternative is gas (600kg/MWh).
• A heat pump with a Coefficient of Performance of 300% saves 3MWh of gas (emitting 200kg/MWh) per MWh electrical.
• “Green H2”: the alternative is gas (200kg/MWh).
• As the conversion efficiencies for electrolysis (green H2) and SMR (grey hydrogen) are equivalent (70%), one 1MWh power saves 1MWh of gas emitting 200kg/MWh.

So electrolysis is climate-efficient only when all other usages listed above are provided with carbon-free power. Any PPA which allocates power to electrolysis when the other usages are fossil powered is climate inefficient.

Question: would an investor possessing its wind farm (or a reliable renewable PPA) operate its electrolysers when power is scarce, fossil powered and expensive? Would the public accept that such an operator would claim a green H2 production, whereas the consumed power could have avoided twice or more CO2 emissions if made available to higher emitters?

Price Stability test

How to limit volatility when a grid might alternate between different production modes?

One of the mains factors of power price volatility is the huge marginal cost difference between renewable (around 0€) and fossil production (for argument’s sake 200€/MWh). On a fully renewable grid, electrolysis might increase demand triggering the entrance of fossil power in the market. Prices will then jump from close to zero to 200€/MWh. To adapt to the price signal, electrolysis reduction will shut down the fossil demand and prices will collapse again.

Any company being simultaneously a significant renewable producer and electrolysis consumer might (willingly or not) create shortages on the renewable market by increasing electrolysis and benefit from it. It is very likely that lawmakers will intervene to avoid such conflicts of interests, for instance by regulating vertical (cartel) integration.

When unloading, stored electrical power has a marginal cost at least 3 times higher than when loaded (considering the conversion losses). When considering the amortisation and maintenance, the ratio between directly produced and stored electricity could easily reach 10. Alternating loading and unloading seems economically untenable.

The stability of the market can be ensured from the demand and offer side:

• From the demand side, TSO’s are developing demand side response with different tools: price signal, smart meters, commercially compensated curtailment… One could imagine additional TSO prerogatives such as requisition rights on the power used by electrolysers, or even bolder, have TSO’s directly operating major electrolysers as part of their statutory duty to stabilise the grid.
• From the offer side, nuclear power could replace gas and coal as the marginal most expensive offer. The market equilibrium shall stabilise at a power price satisfying both the nuclear producer and electrolysis consumer.

Regulation test:

The following regulatory mechanisms have an apparent virtuous effect in the promotion of green hydrogen. However, they focus on the individual emission reduction but fail to measure the collective impact.

• Contract for difference:
• This mechanism will compensate the difference between the cost of electrolysed hydrogen and the methane based “grey H2”. It will erase part of the price signal intended by the carbon tax and subsidise the marginal fossil power production.
• Certification of H2:
• The certification of “green H2” certifies a commercial relation between renewable power producer and the electrolyser. However, it does not certify that the renewable power could not have been used more climate-efficiently by reducing fossil power production.
• Additionality:
• Additionality ensures that additional renewable production has been installed for a given electrolyser. However, it does not ensure optimal allocation of renewable production, nor does it exclude fossil production increase when electrolysing.
• Color codes of H2:
• The electrons on the grid being fungible, the only climate criteria are the marginal emission tracked by a universal carbon tax price signal.

As those mechanisms are unlikely to survive a thorough system analysis, investors take a high risk on relying on them.

The H2 Delegated Act from May 2022, which was heavily criticised by some investors, demonstrated that EU lawmakers are sensitive to the system impact of “green H2” produced in Europe as well as imported. Indeed, who will explain to the Namibian consumer that his national clean and cheap power will be exported as H2 to rich countries whereas he/she shall consume polluting and expensive fossil power? How to explain that the Middle East is ready to export “green H2”, before closing their fossil power production, beside the absence of the CO2 taxation on their domestic power production? Will future “green H2” imports from such countries be subjected to the Carbon Border Adjustment Mechanism, as the physics dictates it?

Investors in electrolysis cannot rely on a privileged access to green and cheap electrons whist leaving the expensive and polluting to other consumers.

Technology test:

Electrolysis efficiency, electrode life cycle, compression, transportation and storage have not reached maturity and a status of “proven technology”. Leakage due to high diffusion properties and high-pressure transportation contribute to global warming, as leaked H2 prolongates the lifetime of GHGs such as methane (the decay and oxidation processes of H2 and CH4 compete by consuming OH hydroxyl radicals scarcely available in the atmosphere).

Question: when will technology and related regulation reach maturity?

Conclusion

Regulation and state support to H2 cannot overrule the physics underlying the H2 production. Assuming that technological issues around production, transportation, storage and consumption are solved, large scale green H2 will become conceivable if and when this fossil production is pushed out of the market.

In a foreseeable future, green H2 can only consume the cheap but scarce renewable overproduction and progress towards technological maturity. It is likely that public funding will prioritise carbon-free production, grids, interconnections and demand side response, and that regulation will focus on the carbon taxation. H2 will become an adjustment variable in the whole energy equation.

In the long run, fossil-free power generation can lead to two scenarios:

• Without nuclear power: green H2 production will be intermittent and electricity price highly variable.
• With nuclear power: carbon free (“green” or “pink”) hydrogen can be produced on a continuous basis and prices will stabilise.

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Michiel Korthals Altes writes this article on his own account. He is a Projects Director at Assystem