Expensive gas has put fossil-based hydrogen out of the money. At today's inflated prices, green hydrogen is *in theory* already cheaper to produce in Europe than both blue and grey H2.
Using models developed by Australian math modelling outfit Keynumbers, Energy Flux calculates that the levelised cost of each hydrogen pathway is currently as follows:
Green H2 = €6.18/kg
Blue H2 = €6.73/kg
Grey H2 = €7.03/kg
Blue is cheaper than grey because the model assumes a very high CO2 capture rate of 90%, meaning grey H2 incurs a comparatively higher cost of purchasing EU carbon allowances.
That's with an EU carbon price of €60/tonne, a European gas price (TTF) at $30/MMBtu, and a uniform cost of capital (discount rate) of 8% for all installations. However, if gas were to fall by one third to $20/MMBtu (still well above average for any season), the levelised costs come in as follows:
Green H2 = €6.18/kg (unchanged)
Blue H2 = €4.97/kg (-26%)
Grey H2 = €4.12/kg (-41%)
This raises several questions: will buyers of methane-based H2 be exposed to these wild price swings? If so, can they hedge their exposure – or will this be undertaken by would-be hydrogen suppliers, which are also big natural gas players (e.g. Shell, BP, Equinor etc.)?
Will these companies make gas available for steam methane reformation (SMR) at fixed or variable prices?
Before green H2 advocates rejoice, remember: the same question applies to the cost of renewable power for electrolysis, which in the above calculations is assumed at €40/MWh.
Is that a fair assumption? Any offtaker consuming electrons at €40/MWh today is foregoing the opportunity to earn much bigger margins reselling them into red-hot power markets.
For example, German spot prices breached €200/MWh this week and baseload futures are trading at a whopping €217/MWh in January 2022. No rational economic actor would turn down that option – if it existed.
A lot depends on the setup. A dedicated green H2 facility at a refinery fed by private wire might not have the ability to resell cheap wind power into the spot market.
But if the hydrogen is intended for power storage/generation then a grid connection is a necessity – in which case reselling is feasible. At €200/MWh, the cost of green H2 shoots up to €14.50/kg – clearly uneconomic.
Will electrolysers shut down when power prices spike (and when the wind stops blowing)? If so, what does this mean for utilisation and hurdle rates? If not, how will they avoid reverting to ‘dirty’ grid or backup power sources?
The global gas price spike was exacerbated by a pronounced period of dunkelflaute. Would several gigawatts of electrolyser load make grid balancing easier, or more difficult?
Price volatility and interconnectedness will be a fact of life for hydrogen production, regardless of the hue. Hydrogen accelerates sector coupling, so it is quite challenging to consider green, blue or grey costs in isolation.
RELATED: Using grid power to produce green hydrogen is among the least ‘green’ options and “little better – or worse – than natural gas,” non-profit ICCT said in a study. But ensuring electrolysers are genuinely powered by renewables is not easy – and sometimes “there’s a trade-off between easy and clean”, the NGO said.
RELATED #2: RES Group and Octopus are investing £3 billion in UK green hydrogen plants that will supply industrial businesses at “no extra cost”. When asked by Energy Flux, Octopus declined to explain how this would work in practice but claimed hydrogen from “low cost” renewables would insulate H2 buyers from “price shocks and volatility in gas markets”. 🤨