Slovenia is studying a hydrogen system designed to operate as a controllable bridge between its electricity and gas networks, shifting the focus from hydrogen production alone towards using electrolysis and digital control as an electricity-system flexibility tool.
Electricity transmission operator ELES, gas system operator Plinovodi and Japan’s Yokogawa Electric signed a memorandum on Sept. 10 covering development of a Slovenian hydrogen ecosystem and an initial demonstration project connecting electricity and gas transmission infrastructure.
The companies said the project would examine a hydrogen plant interfacing with both networks and the digital systems needed to coordinate their operation. Yokogawa will contribute process-control and digital expertise, while ELES and Plinovodi provide electricity and gas-system operating capabilities.
The market significance lies less in hydrogen as a fuel than in the operating flexibility of the electrolyser producing it.
An electrolyser is a large electricity consumer whose output can, within technical and commercial limits, be varied according to power-system conditions.
When renewable electricity is abundant, hydrogen production can increase.
When the electricity system tightens, consumption can fall.
The energy does not disappear. It moves into another carrier that can potentially be stored, transported or consumed later.
That gives hydrogen a characteristic conventional industrial loads rarely have: the ability to transfer energy value not only between hours but also between infrastructure systems.
Sector coupling becomes operational
European energy strategies have discussed sector coupling for years, typically in the context of decarbonising industry or replacing fossil gas.
The Slovenian project adds another dimension.
ELES and Plinovodi want to examine how electricity and gas infrastructure can be orchestrated as one operating system, rather than running independently and merely meeting at the electrolyser.
The partners specifically identified digital solutions for coordinated operation as part of the planned demonstration.
That could make forecasting and control software almost as important as the electrolyser itself.
An optimisation platform could compare electricity prices, system balancing requirements, renewable availability, hydrogen-storage levels, gas-network conditions and downstream hydrogen demand before deciding how the plant should operate.
The commercial dispatch decision would no longer be simply whether today’s hydrogen selling price exceeds today’s electricity cost.
It could incorporate the value of flexibility supplied to the electricity system.
That creates several potential revenue layers.
Hydrogen sales remain the underlying commodity revenue.
Electricity-market optimisation can lower production costs by concentrating consumption in cheaper hours.
Flexible operation could potentially reduce imbalance exposure or provide demand-side system services where market rules permit.
Longer-duration hydrogen storage could also move energy across periods that batteries or ordinary demand response cannot economically cover.
Not all of those revenue streams are available today, and the partners have not announced a commercial operating model.
The first phase is a feasibility study covering technical, operational and commercial pathways.
But that is precisely what makes the project relevant to the wider Southeast European market.
The problem is no longer whether an electrolyser can technically make hydrogen.
It is whether its flexibility can be valued sufficiently to improve project economics.
Electricity surplus becomes feedstock
Slovenia expects higher renewable penetration to increase the need for flexible electricity demand.
Electrolysers could operate particularly during periods when renewable generation exceeds immediate electricity demand or when moving additional power through the network becomes difficult.
Instead of curtailing generation, part of that electricity could become hydrogen.
This is different from building a hydrogen plant that tries to operate at maximum utilisation continuously.
High utilisation lowers the unit cost of expensive electrolysis equipment.
Flexible operation, however, allows the plant to consume cheaper electricity and provide greater value to the power system.
The optimum lies somewhere between the two.
That creates a new investment question for hydrogen developers: whether to maximise annual operating hours or maximise the value of each operating hour.
ELES’s involvement suggests Slovenia intends to examine the second model seriously.
Gas infrastructure offers longer storage horizon
Plinovodi brings another dimension.
Electricity flexibility is usually discussed over minutes or hours through balancing markets and batteries.
Gas infrastructure can store and transport energy over much longer periods.
Hydrogen produced during favourable electricity conditions could therefore move value from the power sector into industrial demand, transport or potentially future hydrogen-network infrastructure.
Plinovodi has also been working on Slovenia’s connection to emerging European hydrogen corridors, giving the project relevance beyond domestic consumption.
If hydrogen networks develop across Central Europe, Slovenian electrolysis would no longer depend exclusively on local buyers.
That could give the electricity system access to a larger flexible demand sink.
In effect, exportable hydrogen demand could create an additional buyer for low-value electricity.
Mobile units add resilience model
The memorandum also covers hydrogen-based mobile backup units for critical electricity infrastructure, designed so that the same equipment could additionally function as fast-charging infrastructure for electric vehicles.
That extends the project beyond energy arbitrage.
ELES and its partners are examining hydrogen as part of resilience planning — supplying backup power where conventional infrastructure is disrupted while using the equipment commercially for other purposes when it is not needed for emergencies.
That is a different asset-utilisation model from conventional standby generation.
Backup equipment normally earns little outside rare emergency events.
A multifunctional unit capable of providing transport charging or other energy services has the potential to generate value during normal operation as well.
Economics remain the test
The biggest challenge remains cost.
Producing low-carbon hydrogen through electrolysis requires substantial equipment investment and large quantities of electricity.
Flexible operation can lower electricity costs, but running an electrolyser fewer hours can increase the capital cost allocated to each kilogram of hydrogen produced.
Digital optimisation therefore cannot rescue an inherently uneconomic project by itself.
The feasibility work will have to establish whether combining several uses — hydrogen production, electricity flexibility, infrastructure resilience and potentially mobility — produces sufficient revenue to justify the investment.
It will also need rules governing how the electrolyser participates in electricity markets and how hydrogen moving into future gas infrastructure is measured, certified and valued.
The Slovenian project is therefore still far from a commercial hydrogen market.
But its structure points towards a more sophisticated role for hydrogen than simply replacing natural gas molecule for molecule.
ELES, Plinovodi and Yokogawa are effectively asking whether an electrolyser can become a dispatchable interface between two energy systems.
If that model proves economic, the value of hydrogen in Southeast Europe may depend as much on when the electrolyser switches on and off as on how many tonnes it produces.
