Every time we receive an industrial decarbonisation request, the client usually brings the answer before the question. "We want to electrify the process." "We are considering hydrogen." "We have heard about CO₂ capture." All three options are technologically viable and all three could be the right one — but not for the same process, not at the same time and not with the same business case behind it.
The problem is not the technology. It is the order in which it has been reached.
The question that is asked first conditions all those that will follow.
A plant manager who arrives with "we want green hydrogen" is, unknowingly, excluding the three or four options that would probably have been cheaper for him. Because the question already carries many implicit decisions: the energy source, the process temperature, the level of investment and, often, a timeline that reality does not support.
The European Clean Industrial Deal and the PNIEC 2023-2030 Spanish plan have put resources and deadlines on the table for all three pathways. But no regulatory document states which is the right one for your plant. This is decided in the energy balance of each process, not in the strategic plan.
First: efficiency and electrification of what can already be electrified
Before talking about new vectors, the method starts with what can be reduced without replacing anything. This means:
- Closing the energy balance with the measurement that already exists (existing meters, billing series)
- Identifying avoidable consumption (compressed air leaks, unrecovered waste heat, vacuum operations, oversized service quality)
- Evaluate the direct electrification of low and medium temperature processes (up to ~200 °C): industrial heat pumps, electric boilers, resistances
- Size the on-site renewable generation with the actual load curve, not with the annual average
Only once this is resolved — or ruled out with numbers — does it make sense to open the conversation about hydrogen or capture.
Hydrogen: it is not "the electric for processes that cannot be electrified"
Renewable hydrogen has a high energy production cost (typically 50-55 kWh electric per kg H₂) and a low volumetric energy density. This makes it competitive where direct electrification does not work and where the molecule adds value as a reactant, not just as an energy vector.
Its clear technical fit is in:
- High temperature processes (>500 °C) where the heat pump does not reach
- Direct reduction (DRI in steelmaking, replacing coking coal)
- Chemical synthesis (ammonia, methanol, refineries) where H₂ is already consumed
- Heavy transport where volumetric energy density matters
The European regulatory framework — RED III and the delegated acts on renewable hydrogen — requires additionality, temporal and geographical correlation to consider H₂ "renewable". This has direct consequences on CapEx: it is not the same project with or without a dedicated PPA.
Capture: only when emissions are unavoidable and concentrated
CO₂ capture is the most expensive route and the one that requires the most external infrastructure (transport and storage). It makes technical sense in:
- Inevitable process emissions (cement, lime, specific chemical process) where the molecule does not come from combustion
- Large concentrated sources with relatively pure CO₂ stream
- Proximity to transport or storage infrastructure (industrial clusters with a common project)
For plants with distributed emissions, low CO₂ concentration in the stream or far from storage hubs, the cost per avoided tonne quickly scales out of the business case.
The order of the questions, in 4 steps
At AUMA we organise the conversation like this:
1. What is the actual thermal and electrical profile of the process? Temperature, continuity, seasonality. Without this, any option is defended with hypotheses.
2. What can be eliminated or reduced without replacing the vector? Efficiency, operations, heat recovery. The cheapest saving is the one that does not need to be electrified or decarbonised.
3. What can be electrified directly with today's technology? Industrial heat pump, resistors, induction. If it comes out in the business case, the other conversation can wait.
4. What remains? Only now is hydrogen, capture, or a combination, compared against the actual emissions residue.
The cost per avoided tonne is what is compared, not the headline
Each of the three routes has a very different cost per tonne of avoided CO₂, and with very high variability depending on the case:
- Efficiency + direct electrification: often negative or very low (<50 €/t) when there is an electrifiable process
- Renewable hydrogen: between ~150-300 €/t, very sensitive to the price of the PPA and the use of the electrolyser
- Industrial capture: between ~80-200 €/t for concentrated emissions, much more for diffuse
Those who compare these numbers at the beginning save themselves projects that should not have reached feasibility study.
What we do
We support industrial management in this decision before it becomes an investment: diagnosis of the real energy profile, prioritised measure portfolio by cost per avoided tonne, and honest assessment of which vector makes sense for which part of the process. 33 years without a matrix or product to place means that if direct electrification is worthwhile, we will say so — even if the order came with hydrogen in the headline.
If you are preparing the decarbonisation plan for your plant, start with the order of the questions. The technological answer is not the first step: it is the consequence.