Hydrogen systems: from kWh to cost and use

Hydrogen is not one technology but a chain, and each link has its own numbers. An electrolyser's efficiency decides how many kilowatt hours are needed per kilogram of gas, that figure feeds into the levelised cost, and the same gas is then refuelled into vehicles or blended into a gas network under ventilation and detection rules. A plain description of hydrogen systems from production to use is the fastest way to see where the losses and the costs actually sit.

What does an electrolyser's efficiency mean from the kilowatt hour to the levelised cost?

Efficiency at the stack is a ratio of energy out to energy in, and it is usually written two ways. The higher heating value of hydrogen is about 39.4 kilowatt hours per kilogram, the lower heating value about 33.3. A stack quoted at 80 percent on the lower heating value therefore consumes roughly 41 to 42 kilowatt hours of electricity per kilogram produced, and a stack at 65 percent consumes about 51. The gap between those two numbers is the whole argument.

That electricity figure is the largest single term in the levelised cost of hydrogen. A levelised cost divides all lifetime spending by all lifetime kilograms, so it includes the stack, the power electronics, the balance of plant, maintenance, stack replacement after roughly 40,000 to 80,000 operating hours, and the price of the electricity itself. When power is cheap, efficiency matters less; when power is expensive, a few percentage points of stack efficiency move the final cost per kilogram more than any other line item.

Utilisation is the second lever. An electrolyser rated at 1 megawatt that runs 2,000 hours a year spreads its capital cost over far fewer kilograms than one that runs 6,000 hours. Operators who pair electrolysers with wind or solar output face an intermittent supply, so they size the stack against the hours the plant can actually absorb rather than against the nameplate rating. Curtailed renewable power, sold at a low or zero price, is what makes many projects close.

How is a fuel cell vehicle refuelled?

Refuelling a hydrogen car looks like refuelling a petrol car and is not. The dispenser locks onto the vehicle's receptacle, a communication link between pump and car confirms the tank's pressure rating and temperature, and gas flows at 350 bar for buses and heavy trucks or 700 bar for passenger cars. A fill takes three to five minutes, comparable to a petrol stop and far shorter than a battery charge on a long trip.

The physics inside the tank is the part drivers never see. Compressing gas heats it, and a tank must not exceed 85 degrees Celsius, so dispensers pre cool the hydrogen, often to minus 40 degrees Celsius, before it enters the vehicle. The protocol that governs this exchange, SAE J2601, sets the pressure ramp rate and the temperature window so that a full fill is reached without overheating the composite overwrap.

Payload is the trade the driver does notice. A 700 bar tank storing 5 to 6 kilograms of hydrogen weighs considerably more than the fuel it holds, and the carbon fibre composite vessel takes volume that a petrol tank of the same energy would not. For a passenger car the penalty is modest. For a long haul truck, where range and refuelling time decide the route, the calculation changes and 350 bar systems with larger tanks become common.

How is hydrogen blended into a gas network?

Blending means injecting hydrogen into an existing natural gas pipeline so that the mixture is burned by ordinary appliances. Most networks tolerate a few percent by volume without modification, and some jurisdictions allow up to 20 percent. The limit is set by the end users: a boiler, a cooker, and a gas turbine each accept a different proportion before flame behaviour or emissions change.

Hydrogen carries about one third of the energy of the same volume of methane, so a blend of 20 percent hydrogen delivers roughly 7 percent less energy per cubic metre. Meters and billing that work on volume rather than energy have to be adjusted, and industrial customers with tight process heat requirements are usually the first to object.

Pipelines themselves are the smaller problem. Hydrogen embrittles some steels, particularly at high pressure and at welds, so operators inspect and sometimes derate older sections. Compressors need different seals, and the whole chain from injection point to end user has to be modelled before a blend is approved.

What safety measures apply to hydrogen handling?

Hydrogen is flammable over a wide range, roughly 4 to 75 percent in air, and it ignites with very little energy. It is also the lightest gas, so it disperses upward quickly in the open, which is why outdoor installations are far easier to manage than indoor ones. The two controls that carry most of the weight are ventilation and detection.

Ventilation keeps any leak below the lower flammability limit. Enclosed rooms with electrolysers, compressors, or dispensers are built with high level vents, because hydrogen accumulates at the ceiling, and with enough air changes per hour to dilute a worst case release. Detection follows the same logic: sensors are placed at the highest points of the space, often in redundant pairs, and they trigger alarms, isolation of the gas supply, and shutdown of electrical equipment that is not rated for the hazard.

Ignition control is the third layer. Equipment in a classified area is specified for the zone, static bonding and grounding are mandatory during transfers, and vent stacks are designed so that a release cannot be drawn back into an intake. These are the same principles used in refineries and chemical plants, applied to a gas that is harder to contain but easier to disperse.

Where does the hydrogen actually go?

Three destinations dominate. Refining uses hydrogen to remove sulphur from fuels, ammonia production for fertiliser consumes it in large volumes, and steelmaking is testing it as a replacement for coke in direct reduced iron. These are industrial clusters, where several plants share pipelines, storage, and a single large supply, and where an offtake contract signed before construction is what makes the project bankable.

Stationary fuel cells are the smaller but growing use. A cell running on hydrogen or on reformed gas can supply backup power to a building or a microgrid, with a runtime set by the size of the tank rather than by a battery's discharge curve. Data centres, hospitals, and remote sites have installed them where a diesel generator would otherwise sit.

Mobility sits between the two. Buses return to a depot and refuel at a single dispenser, which suits the technology. Long haul trucks run fixed corridors where a handful of stations can cover a route. Passenger cars depend on a network dense enough that a driver never plans around it, and that density is the slowest part of the chain to build.

The chain is only as strong as its least efficient link. A stack that consumes 50 kilowatt hours per kilogram, a station that cannot fill a truck in fifteen minutes, or a pipeline that accepts only 5 percent hydrogen each set a ceiling on what the rest can deliver. Reading the numbers at each stage, from the kilowatt hour to the levelised cost to the blend limit, is what turns a general enthusiasm into a project that can be financed.