Engineering tools
Four working models, free to use and free of sign-up. They run entirely in your browser, nothing you type is sent anywhere, and every default is a literature value with its range shown, so you can see immediately whether your case sits inside it.
- 01
- Green hydrogen cost model
- 02
- Power-to-X pathway simulator
- 03
- Biowaste-to-fuel calculator
- 04
- Electrolyser technology comparison
What does a kilogram of hydrogen actually cost from this plant?
Full levelised cost: capital recovery, electricity, fixed O&M, discounted stack replacements and water. Then a sensitivity ranking that shows which two assumptions the answer really turns on.
Inputs
Scale alone does not move LCOH here: capital cost is entered per kW, so the plant scales linearly.
4,380 full-load hours a year. Grid-connected runs high; a dedicated wind or solar farm rarely clears 55%.
Usually the largest single term. At this price the power alone costs EUR 2.12/kg.
Shaded band is the literature range for PEM: 50–58 kWh/kg. LHV efficiency 62.9%.
Shaded band is the PEM range: 700–1800 EUR/kW. Total installed cost EUR 110.0M.
1 stack replacement at 60,000 operating hours, discounted to the year each falls due.
Results
Levelised cost of hydrogen
4.14EUR / kg H₂
Proton exchange membrane (PEM) at 50% capacity factor, 40 EUR/MWh.
- Hydrogen output
- 8,264t/yr
- Electricity drawn
- 438GWh/yr
- By-product oxygen
- 65,584t/yr
- Process water
- 99,170m³/yr
Cost breakdown
| Component | Cost (EUR/kg) | Share |
|---|---|---|
| Electricity | 2.1251% | |
| Capital | 1.3633% | |
| Fixed O&M | 0.4010% | |
| Stack replacement | 0.246% | |
| Water | 0.021% | |
| LCOH | 4.14 EUR/kg |
What actually moves the answer
Each input swung ±30% on its own, everything else held. The ranking is the point: the top two are worth negotiating, the bottom two are not.
| Input | Low case | High case |
|---|---|---|
| Specific consumption | 2.90–5.37 | |
| Electricity price | 3.50–4.77 | |
| CAPEX | 3.54–4.73 | |
| Capacity factor | 3.73–4.87 | |
| Project life | 3.99–4.44 | |
| Discount rate | 3.93–4.36 | |
| Stack life | 4.07–4.38 | |
| Fixed O&M | 4.02–4.26 |
- Lower result
- Higher result
- ±30%, one input at a time
Assumptions
LCOH is the constant price per kg at which discounted revenue equals discounted cost: (CAPEX·CRF + fixed O&M + discounted stack replacements + electricity + water) ÷ annual output. Hydrogen energy is lower heating value, 33.33 kWh/kg. Water is charged at 12 kg per kg H₂ and EUR 2/m³, above the stoichiometric 8.94 kg/kg to allow for demineralisation reject. Stack replacements are discounted individually at the year each falls due, so one beyond the project horizon costs nothing. Technology defaults are mid-range values from the IEA Global Hydrogen Review and IRENA cost studies; the shaded band on each slider is that source’s range. Not included: grid connection, compression beyond stack delivery pressure, storage, and any subsidy.
What can this much renewable power actually make?
Routes a wind or solar input through electrolysis into hydrogen, e-methane, e-methanol or e-ammonia, closing the mass balance stoichiometrically and the energy balance stage by stage.
Inputs
736 GWh a year into the plant. Onshore wind is typically 25–40%, offshore 40–55%, solar PV 10–25%.
Reaction
CO₂ + 3 H₂ → CH₃OH + H₂O
Shipping fuel and a chemical platform, liquid at ambient conditions, so it moves through existing infrastructure.
Liquid at ambient; 4.4 kWh/L.
Results
e-Methanol output
67,555t CH3OH / yr
50.8% of the electricity in ends up as chemical energy in the product.
- Hydrogen made
- 13,565t/yr
- CO₂ consumed
- 92,786t/yr
- Process water
- 121,218m³/yr
- Fossil CO₂ displaced
- 50,666t/yr
Where the energy goes
Every conversion step costs energy. This is why making a molecule is never as efficient as using the electricity directly, and why the products worth making are the ones electricity cannot serve.
Against the fossil incumbent
Displacing 67,555 t/yr of conventional methanol avoids about 50,666 t CO₂e a year. Natural-gas methanol, production only, ~0.5–1.1 kg CO₂/kg.
Separately, 92,786 t/yr of CO₂ is chemically bound into the product. That is only a climate benefit if the carbon is biogenic or captured from air. Fossil CO₂ routed through a fuel is released again on combustion.
Assumptions
Mass balances are stoichiometric: 0.189 kg H₂ and 1.373 kg CO₂ per kg of e-methanol, computed from molar masses rather than assumed. A single yield term (94%) carries real-plant losses to the purge stream, and synthesis draws 0.25 kWh of electricity per kg of product for compression and separation, taken from the same generation, so it competes with hydrogen production rather than arriving free. Energies are lower heating value. Excluded: heat integration credits (these reactions are exothermic and a real plant recovers much of it), CO₂ capture energy, storage and distribution.
What is my waste stream worth as fuel?
Anaerobic digestion yields for real feedstocks, then the step most plants skip: what the biogenic CO₂ separated during upgrading is worth if it is hydrogenated instead of vented.
Inputs
Fresh matter as received, not dry solids: quoting the dry-basis figure is the most common way these numbers get overstated by three to five times.
Defaults to the cattle manure value and resets when you change feedstock, override it with your own digester's number. Literature range: 15–25 m³/t.
On this feedstock
Low yield per tonne, but it arrives free and continuously, and digesting it also removes the storage methane emission.
Results
Total gas output, CO₂ upgraded
17.2GWh / yr
1.64× what the same feedstock yields when the CO₂ is vented (10.5 GWh).
- Raw biogas
- 1.75Mm³/yr
- Biomethane
- 753t/yr
- Biogenic CO₂ separated
- 1,384t/yr
- e-Methane potential
- 484t/yr
Energy output, both routes
The same tonnage of waste, with and without hydrogenating the CO₂ that upgrading separates out anyway.
| Component | Cost (GWh/yr) | Share |
|---|---|---|
| Biomethane (conventional) | 10.4561% | |
| e-Methane from the separated CO₂ | 6.7339% | |
| Combined | 17.18 GWh/yr |
What the upgrade costs
Converting that CO₂ needs 254 t/yr of hydrogen, which takes 13.4 GWh/yr of renewable electricity on PEM: 1.53 MW running flat out, or about 4.38 MW of onshore wind at a 35% capacity factor.
That is the real trade the project has to price: renewable electricity and an electrolyser, against roughly 64% more gas from waste you are already collecting and a CO₂ stream you are already separating.
Assumptions
Methane yields are per tonne of fresh matter, from the ranges reported for agricultural digestion; the slider defaults to the selected feedstock’s value, shades its literature band, and stays editable so you can enter your own measured yield. Raw biogas is taken at 60% CH₄ with the balance CO₂, and gas volumes convert at STP densities (CH₄ 0.7168, CO₂ 1.977 kg/m³). Methanation is Sabatier, CO₂ + 4 H₂ → CH₄ + 2 H₂O, at 96% yield. Methane energy is lower heating value, 13.89 kWh/kg. Excluded: parasitic load of the digester and the upgrading unit, digestate handling and its fertiliser value, gate fees, and the avoided methane emission from open manure storage, which is real and often the largest climate term of all.
Which stack technology fits my duty cycle?
Alkaline, PEM, SOEC and AEM side by side on the parameters that decide the choice (specific consumption, capital cost, stack life, minimum load and readiness), with the trade-offs stated rather than implied.
| Parameter | AELAlkaline | PEMProton exchange membrane | SOECSolid oxide | AEMAnion exchange membrane |
|---|---|---|---|---|
| Specific consumptionkWh/kg H₂ | 50 (47–55) | 53 (50–58) | 40 (37–42) | 52 (48–57) |
| LHV efficiency33.33 kWh/kg ÷ specific consumption | 67% | 63% | 83% | 64% |
| System CAPEXEUR/kW | 800 (500–1400) | 1100 (700–1800) | 2400 (2000–4500) | 900 (600–1500) |
| Stack lifeoperating hours | 75,000 | 60,000 | 25,000 | 30,000 |
| Minimum stable loadHow far down it can turn before it has to stop | 15% | 5% | 30% | 5% |
| Delivery pressurebar | 1–30 | 30–70 | 1–15 | 10–35 |
| Operating temperature°C | 60–90 | 50–80 | 700–850 | 50–70 |
| Technology readiness | TRL 9 | TRL 9 | TRL 7 | TRL 6 |
| Chosen for | The mature, lowest-capital route. Slow to ramp and a high minimum load, so it suits steady baseload operation. | Follows a wind or solar profile down to 5% load and delivers at pressure. The default where the power supply is variable. | Lowest electricity demand of any route, because steam supplies part of the reaction enthalpy. Only pays off beside a waste-heat source. | Aims at PEM's flexibility without its iridium and platinum. Still pre-commercial, and stack life is the open question. |
Assumptions
Central values are mid-range figures for commercial-scale systems from the IEA Global Hydrogen Review and IRENA cost studies; the bracketed range is that source’s spread. SOEC’s specific consumption is electrical only: it also needs roughly 0.6–0.8 kWh/kg as steam, which is why it beats the low-temperature routes on electricity but only pays off beside a heat source. Efficiency is on lower heating value throughout; quoting HHV instead would raise every figure here by about 18%, which is the most common way these comparisons are made to disagree.
These are teaching and screening models, not a substitute for a plant study
They are built to be right about the physics and honest about what they leave out, which makes them useful for sizing an idea, checking someone else’s number, or teaching the trade-offs. They are not a front-end engineering design. A real project needs site data, a heat integration study, equipment quotes and a financing structure. That is the work itself, and it is what the practice does.
Every calculation runs locally in your browser. Nothing you type is transmitted, logged or stored.
Talk about a real study