Green hydrogen will not become cheaper than grey hydrogen everywhere at the same time. The cost crossover will occur first in specific regions, sectors, and industrial sites where low-cost clean electricity, high utilisation, and policy- or product-level carbon value converge.
For industrial users, this changes the question. The most useful question is not “When will green hydrogen be cheaper everywhere?” It is “Where can green hydrogen already support a practical, scalable decarbonisation strategy?”
The cost gap is still real
Grey hydrogen remains cheaper in many markets because it is produced via steam methane reforming, a mature process that uses natural gas. It benefits from established infrastructure, low capital costs and decades of industrial optimisation.
Green hydrogen is produced through electrolysis. Electricity is used to split water into hydrogen and oxygen. When that electricity comes from renewable sources, the production pathway can significantly reduce emissions. The challenge is that electrolysis remains more expensive than conventional hydrogen production in most regions.
The European Hydrogen Observatory tracks levelised hydrogen production costs across steam methane reforming, steam methane reforming with carbon capture, grid-connected electrolysis and electrolysis directly connected to renewable energy. Its dataset covers the reference years 2022, 2023, and 2024 and uses energy price data, renewable generation assumptions, and hydrogen technology inputs to compare production pathways across Europe. [1]
The United States shows a similar cost challenge. The US Department of Energy’s 2024 PEM electrolyser benchmark estimates the cost of renewable hydrogen from current PEM technology at approximately $5-$7/kg without subsidies. The same benchmark notes that its LCOH values refer only to hydrogen production and exclude compression, storage, distribution and dispensing costs. [2]
This distinction is important. Green hydrogen is not only competing against grey hydrogen at the production plant. In many applications, it must also compete after accounting for storage, compression, transport, and final integration.
Why is there no single crossover year
Many discussions about green hydrogen call for a single date. Will it become cheaper in 2030? 2035? Later?
That framing is too simple.
The levelised cost of hydrogen depends on several variables. These include electricity prices, electrolyser CAPEX, utilisation rate, financing costs, grid charges, system efficiency, operating costs, storage needs, and site integration requirements.
Electricity is the dominant cost lever. The DOE benchmark shows this clearly. A hybrid wind-and-solar configuration with 3.3¢/kWh electricity and a 74% capacity factor produces hydrogen at around $5.20/kg, assuming a $2,000/kW installed electrolyser cost. A grid-average case with 8.3¢/kWh electricity and a 97% capacity factor reaches around $7.50/kg. [2]
This means utilisation matters, but the electricity price can matter even more.
The International Energy Agency’s 2025 assumptions annex also shows why regional differences are significant. It places 2024 water electrolysis CAPEX at $2,000–2,600/kWe globally, compared with $600–1,200/kWe in China. It also shows regional differences in renewable electricity costs, with 2024 solar PV LCOE for good-resource conditions ranging from $20/MWh in China to $36/MWh in the United States. [3]
As a result, the same hydrogen project can look commercially promising in one market and uncompetitive in another.
The three conditions that move green hydrogen closer to parity
Green hydrogen approaches grey hydrogen when three conditions align.
First, the project needs access to cheap, clean electricity. Co-located renewable generation, hybrid wind-and-solar systems, or long-term power purchase agreements can reduce exposure to volatile electricity prices.
Second, the project needs a steady demand for hydrogen. Industrial sites with continuous production can run electrolysers for more hours per year. This spreads capital costs over a larger volume of hydrogen, improving the business case.
Third, the project needs policy support or product-level carbon value. This can include tax credits, operating support, electricity charge exemptions, carbon contracts for difference, green public procurement or customer demand for lower-carbon products.
India provides a useful example of how policy can affect the cost curve. The National Green Hydrogen Mission cost report estimates that without incentives, green hydrogen production in India can range from INR 439–477/kg. It also states that electricity accounts for 65%-75% of the cost of green hydrogen in the absence of incentives. In Odisha, the report shows that incentives can reduce the cost of green hydrogen to INR 218/kg, below the grey hydrogen benchmark of INR 242/kg under the stated gas price assumption. [4]
This does not mean every project in India has reached parity. It shows that policy design, electricity costs, and project location can materially affect the economics.
Carbon pricing helps, but it is not enough on its own
Carbon pricing can improve the relative position of green hydrogen by increasing the cost of unabated fossil-based production. Europe is the most advanced example because the EU Emissions Trading System imposes a carbon price on covered sectors. [5]
However, current carbon prices do not automatically close the gap everywhere. Grey hydrogen emissions are significant, but the cost difference between green and grey hydrogen can still be larger than the carbon-cost impact in many markets.
This means carbon pricing should be seen as one part of the transition, not the only mechanism. Green hydrogen adoption also needs low-cost renewable electricity, efficient electrolyser deployment, high utilisation and industrial demand that can justify investment.
Which industries are likely to move first?
The first cost crossover markets are likely to be industries with continuous hydrogen demand and clear integration points.
Ammonia, fertilisers, basic chemicals and selected refining applications are early candidates because they already use hydrogen at scale. These sectors can often support high electrolyser utilisation and the integration of hydrogen into existing production systems.
Steel can also move early in selected projects, but it remains more challenging than ammonia. Hydrogen-based direct-reduced iron is technically proven, yet it requires major capital investment and large volumes of hydrogen. The clearest opportunities are new plants designed around hydrogen from the outset. In these cases, the business case rarely depends on hydrogen cost parity alone. It usually also relies on carbon pricing, regulatory support, or a premium for lower-carbon steel in regulated or high-value markets.
Heavy transport and hydrogen-to-power applications are likely to move later. They often require additional compression, storage, distribution, dispensing or reconversion. These costs are central to the real economics of the application, but they are not always included in production-level LCOH figures. The DOE explicitly states that its PEM benchmark excludes compression, storage, distribution and dispensing. [2]
This is why plant-gate comparisons can be misleading. A kilogram of hydrogen produced at the electrolyser is not the same as a kilogram delivered, stored and used in a vehicle, turbine or industrial process.
Why onsite production can change the business case
For industrial users, the economics of hydrogen are not only about the market price per kilogram. They are also about how hydrogen is produced, delivered, stored and integrated.
On-site hydrogen production can reduce dependence on long-distance hydrogen delivery and emerging transport infrastructure. It can also be designed around the actual demand profile of the industrial site.
This is especially relevant for industrial processes with predictable demand, available clean power and clear integration points. Instead of waiting for a mature hydrogen network, companies can evaluate hydrogen where it fits their own operations first.
A modular onsite system can start with a defined use case and expand over time. This can reduce the risk of overbuilding, support phased investment and allow companies to adapt as renewable electricity prices, carbon regulation and hydrogen demand evolve.
For Hydrogenera, this is where practical integration matters. Hydrogen systems should be designed around site conditions, operating requirements, safety needs and long-term decarbonisation goals.
The crossover will be sector by sector
Green hydrogen will not reach cost competitiveness through one global tipping point. It will develop through regional and sector-specific opportunities.
The strongest early opportunities are likely to share several characteristics:
• Continuous or predictable hydrogen demand
• Access to low-cost renewable electricity
• A clear industrial integration point
• Limited need for long-distance hydrogen transport
• Policy support or customer demand for lower-carbon products
• A system design that can scale over time
This is why ammonia, chemicals and selected steel projects are expected to move before heavy transport or hydrogen-to-power in most markets.
The cost curve is also not static. The IEA’s 2025 assumptions annex projects lower electrolysis CAPEX by 2030 under its Stated Policies Scenario, from $2,000–2,600/kWe in 2024 to $1,400–1,820/kWe globally. For China, it projects a reduction from $600–1,200/kWe to $450–900/kWe. [3]
If electrolyser costs fall, renewable electricity becomes cheaper and utilisation improves, the crossover will expand to more projects and sectors.
What industrial companies should evaluate now?
Industrial companies should not wait for a universal parity headline. They should evaluate whether green hydrogen already fits specific processes and future decarbonisation goals.
A practical assessment should start with six questions:
- What is the real cost of clean electricity at the site?
- How many hours per year can the electrolyser operate?
- Does the site already consume hydrogen, natural gas or another fuel that hydrogen can partially or fully replace?
- Will the project require compression, storage, distribution or additional conditioning?
- Is there policy support, carbon exposure or customer demand for lower-carbon products?
- Can the system start at a practical scale and expand over time?
These questions are more useful than asking when green hydrogen becomes cheaper everywhere. The strongest projects will be those where hydrogen is integrated into a clear industrial use case.
The practical answer
Green hydrogen will first become cheaper than grey hydrogen in projects with low-cost clean electricity, high utilisation, and strong industrial demand.
That means the earliest opportunities are likely to appear in ammonia, chemicals, selected refining applications and specific steel projects. Heavy transport and hydrogen-to-power will usually require more time, stronger policy support, or very low-cost electricity due to their additional infrastructure and utilisation challenges.
In some favourable locations and sectors, project-level crossover can happen before 2030. In broader industrial markets, the crossover is more likely to occur over the 2030s as renewable electricity becomes cheaper, electrolyser costs decline, and policy frameworks strengthen.
The future of green hydrogen will not be determined by a single global price point. It will be built sector by sector, site by site.
What this means for industrial decarbonisation
For industrial companies, green hydrogen is not only a fuel comparison. It is a strategic decision about energy security, emissions reduction and long-term competitiveness.
The companies that move first will not necessarily be those waiting for the lowest possible hydrogen price. They will be the ones who understand where hydrogen can solve real operational problems, reduce exposure to fossil fuels, and create value in lower-carbon products.
Hydrogenera supports this transition by developing modular hydrogen systems designed to operate under real industrial conditions. This includes site-specific demand, power availability, integration requirements and future scalability.
For industrial users, the next step is not to ask whether green hydrogen is cheaper everywhere. The next step is to identify where it can already fit, where it can scale, and where it can support a practical decarbonisation roadmap.
Hydrogenera works with industrial companies to assess where green hydrogen can support existing processes and long-term decarbonisation goals.
To explore whether onsite hydrogen production can fit your industrial operation, contact Hydrogenera for a site-specific assessment. https://hydrogenera.eu/
Sources
[1] European Hydrogen Observatory, “Cost of hydrogen production”, (European Hydrogen Observatory)
[2] US Department of Energy, “Clean Hydrogen Production Cost Scenarios with PEM Electrolyzer Technology”, 2024, (Hydrogen Program)
[3] International Energy Agency, “Global Hydrogen Review 2025 Assumptions Annex”, (IEA Blob Storage)
[4] Ministry of New and Renewable Energy, Government of India, “Fueling the Future. Green Hydrogen Report”, (Fueling the future: Igniting India’s green hydrogen ambitions)
[5] International Carbon Action Partnership, “EU Emissions Trading System”, (icapcarbonaction.com)
