The conventional wisdom is that electrolysers need to be powered as close to 24 hours a day as possible to get the cheapest levelised cost of hydrogen (LCOH) — after all, the capital costs for electrolysis systems are the same regardless of how often they are in operation (see panel below).
However, if the project operator is relying on variable power prices — via the wholesale market or non-fixed power-purchase agreements (PPAs) — the cheapest green hydrogen could be produced by switching the electrolyser off when electricity prices are peaking and below a certain level, according to analysis by Oslo-based energy consultant Thema.
This is because when there is more wind and solar power available than can be absorbed by the grid, market prices fall to zero or even into negative territory, when users are actually paid to consume unwanted electricity.
“Electricity costs make up the lion’s share of hydrogen production cost, especially if they are as high as they are today,” Thema manager Robert Seguin points out.
Modelling its calculations on forecasts for the wholesale power market in Germany in 2030 — with an average spot price of €81/MWh and prices ranging from negative to €150/MWh — Thema found that the LCOH could be significantly reduced by limiting production to low-cost hours.
“There is an optimum depending on the input cost parameters and the volatility of the electricity price, which in turn depends on the available flexibility in the system,” Seguin tells Hydrogen Insight.
“Even in terms of total profit, flexible operation can be favourable, although you produce less hydrogen.”
The conclusion, spelled out in Thema’s new Technology Outlook report, points to excess wind and solar power as a possibly more profitable energy source for green hydrogen producers than via constant grid electricity (which would have to be accompanied by renewable energy certificates or guarantees of origin to be labelled as green).
While grid electricity might not be allowed under the EU’s expected additionality rules, which would force green H2 producers to secure all their renewable energy from dedicated sources, the analysis is still relevant if clean electricity is bought under PPAs without fixed prices, Seguin explains.
“In principle, PPAs are a tool to redistribute market risks, not eliminate them,” he says. “How they are redistributed between producer and off-taker, the hydrogen producer in our case, is not defined. It is up to the contract partners how to design the contract details and thus this redistribution — fixed price, price caps, market indexed, volume-based or a combination of the above.
“To make things even more complicated, they can also be combined with other hedging products or Contracts for Difference, for example.”
As Seguin points out: “Electricity costs make up the lion’s share of hydrogen production cost, especially if they are as high as they are today.”
In its landmark 2019 report, The Future of Hydrogen, the International Energy Agency found that green hydrogen would be cheaper the more hours per year an electrolyser was in operation.
"As electrolyser operating hours increase, the impact of CAPEX costs on the levelised cost of hydrogen declines and the impact of electricity costs rises," it explained. "Low-cost electricity available at a level to ensure the electrolyser can operate at relatively high full load hours is therefore essential for the production of low-cost hydrogen."
The report continued: "In electricity systems with increasing shares of variable renewables, surplus electricity may be available at low cost. Producing hydrogen through electrolysis and storing the hydrogen for later use could be one way to take advantage of this surplus electricity, but if surplus electricity is only available on an occasional basis it is unlikely to make sense to rely on it to keep costs down. Running the electrolyser at high full load hours and paying for the additional electricity can actually be cheaper than just relying on surplus electricity with low full load hours."
It added: "Very low-cost electricity is generally available only for a very few hours within a year, which implies a low utilisation of the electrolyser and high hydrogen costs that reflect CAPEX costs.
"With increasing hours, electricity costs increase, but the higher utilisation of the electrolyser leads to a decline in the cost of producing a unit of hydrogen up to an optimum level at around 3,000–6,000 equivalent full load hours. Beyond that, higher electricity prices during peak hours lead to an increase in hydrogen unit production costs."