Hydrogen power procurement needs a production schedule

Kassø’s operating strategy includes both selling electricity and buying it. In a Mitsui interview, the project team describes adjusting production to solar output and electricity prices, selling some surplus power and sometimes purchasing from the market. The adjacent solar plant is part of a wider operating decision about when to use electricity for e-methanol production.

For an electrolyser developer, that example makes the procurement question concrete. A power offer supplies energy at particular times and on particular terms. The production plan has to turn that energy into hydrogen the customer can use. A quoted price per megawatt-hour is one input; the usable hours and resulting delivery profile determine what the plant can earn from it.

Cheap hours leave a fixed-cost bill

The IEA’s 2019 technical analysis explains the tradeoff. More full-load hours spread electrolyser investment over more hydrogen, while electricity becomes a larger part of unit cost. Operating only on occasional surplus electricity can yield a higher hydrogen cost than buying additional power and producing for longer.

The mechanism is the production denominator. An electrolyser incurs capital-related charges across the year, including periods with little output. With annual fixed charges and energy use per kilogram held constant, halving equivalent full-load hours doubles the fixed-charge contribution per kilogram. The electricity component can fall at the same time, so the change in total cost depends on both effects.

Equivalent full-load hours measure annual electrical use relative to rated input capacity. They are not simply a count of hours when equipment is switched on. A plant operating at partial load can be available for many calendar hours but accumulate fewer full-load hours. That distinction matters when a power offer promises access to a window of time without a matching energy quantity.

Running longer changes the electricity price you pay

Adding hours also changes the set of electricity prices the plant accepts. The IEA illustrates this using Japanese 2018 spot-price data: initial extra operating hours spread fixed costs, while adding progressively more expensive hours can eventually raise unit cost. The example is a historical model of the mechanism, with assumed equipment and financing inputs.

A project assessment should therefore use the prices of the hours in which the plant would actually consume power. An annual market average can include expensive hours the operator avoids, or cheap hours that are unavailable under the proposed contract. A fixed-price agreement can also have a variable delivery profile. The price and energy schedule have to be evaluated together.

For a site with its own renewable generation, selling power creates another choice. Electricity used in hydrogen production cannot be sold in the same interval. Mitsui’s description of Kassø makes that alternative explicit. The relevant comparison is the value of using the available electricity in production against the revenue from selling it, together with the effect on downstream supply commitments.

Different arrangements put variability in different places

The IEA identifies dedicated renewable generation as an alternative to grid supply and discusses combining wind and solar in suitable locations. The advantage depends on the resulting production profile and the connection to users. A good resource at a remote site can still require additional infrastructure to reach the customer.

These options change the information needed in a procurement discussion. A developer comparing grid purchases with dedicated generation needs a common annual production case, then the cost of serving the same delivery requirement. Comparing one option’s plant-gate output with another option’s firm supply at the customer would mix two different products.

The customer’s schedule changes the system boundary

A customer requiring regular hydrogen deliveries may not be able to absorb the electrolyser’s cheapest operating pattern directly. Depending on the arrangement, the gap can be covered with storage, alternative supply or flexibility in the consuming process. Each option changes the investment or operating costs included in the supply proposal. It also changes which party must respond when production and demand diverge.

This is where a low production-cost estimate can lose commercial relevance. If it assumes the plant stops whenever power is expensive, the corresponding supply offer needs to explain how deliveries continue or how the customer accepts the interruption. If output is increased to meet a firmer schedule, the resulting electricity costs belong in the same comparison.

For procurement, a useful offer therefore connects price to a time profile, expected usable energy and a delivery obligation. Kassø’s owner-described operating flexibility is one example of making those choices within an integrated plant. Another project may allocate them across a power supplier, hydrogen producer and industrial customer. The contract discussion then becomes specific: who can vary production, who provides cover, and what that flexibility costs.

Related analyses

• Kassø’s methanol customer base expands into chemicals and road fuels
• Normand’Hy connects its refinery customer’s power and hydrogen supply
• Holland Hydrogen I: a completed route and a later production milestone
• Korea’s 2026 hydrogen-power plan changes the customer for clean fuel

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