India will build substantial green hydrogen capacity over the next decade. How much of it becomes a repeatable, financeable business turns on the three decisions: a buyer who can actually pay, a plant configured around that buyer’s delivered cost and certification requirements, and each risk placed with the party able to carry it.
September 08, 2026. By News Bureau
Developers such as ACME, NTPC Renewable Energy and Oriana Power have secured offtake contracts through the Solar Energy Corporation of India (SECI) for green ammonia, a derivative of green hydrogen, and Reliance signed a 15-year supply agreement with Samsung C&T in 2026.
The case for entry is understandable: developers already know how to aggregate land, build large power projects, manage auctions and raise project finance. Those capabilities will only take them so far. Green hydrogen is a different business from renewable generation with an electrolyser attached, and the buyer has to be found before the plant is built. Three decisions will largely determine which developers move from announced capacity to scalable businesses: where to find bankable demand, what configuration can serve it competitively, and how to allocate risk and capital to reach final investment decision (FID).
1. Where is the bankable demand?
The first question is who will sign a contract for green hydrogen or its derivatives now; long-run demand forecasts are secondary. Demand is the weak link globally. The International Energy Agency (IEA) estimates that around 1.7 million tonnes per annum of new low-emissions hydrogen offtake agreements were signed in 2025, but only about one-fifth of those volumes were firm commitments.
For Indian developers, the choice is usually framed as domestic versus export, though the more useful distinction is bankable versus unbankable. Domestic markets start with an advantage: fertiliser plants and refineries already consume hydrogen or ammonia, and SECI’s green ammonia programme had facilitated agreements covering 670,000 tonnes per annum by March 2026. But most of those users benchmark against cheaper fossil-based alternatives and cannot absorb a large green premium without mandates, subsidies or cost pass-through.
Export markets solve a different problem. Policy in Europe, Japan and South Korea creates a willingness to pay that does not yet exist in India. Those buyers can only use molecules that satisfy their certification rules, so an export contract is bankable only if the plant is built to meet them.
Bankable demand means a price that clears, a counterparty a lender will underwrite, volume and tenor long enough to carry debt, certification the buyer can use, and a realistic probability of reaching FID. Developers should look for demand that meets that test and build the project backwards from those customers.
2. What project configuration can serve that demand competitively?
The second decision is what to build. The economics are dominated by electricity: India’s 5 million tonne target could require around 135 GW of additional renewable capacity and 35-55 GW of electrolysers, with the bulk of the investment in generation rather than electrolysis. That is a real advantage for renewable developers, and it makes power configuration the most consequential choice in the project.
A developer must settle the solar-wind mix, whether power is captive or contracted, the electrolyser utilisation rate, the need for storage, and how intermittency shapes the production profile. Certification narrows those choices further: Europe’s rules on renewable fuels of non-biological origin (RFNBO) tie hydrogen output to qualifying renewable electricity, with temporal matching monthly until the end of 2029 and hourly from January 2030. Hourly matching reshapes storage sizing, metering and procurement, and it cannot be retrofitted after construction.
What counts is the cost of delivering a compliant molecule to the customer, which is not the same as the cheapest renewable tariff. A fertiliser contract may favour production near existing ammonia infrastructure, while an export contract may favour a coastal complex with storage, desalination and port access.
Ownership follows the same logic: a developer does not need to own every asset between generation and the customer, but it does need control over the interfaces that could stop it performing. Where failure of an asset would halt delivery, invalidate certification or change contract economics, the developer needs ownership or a robust contractual equivalent; where the interface affects only cost and suppliers are competitive, contracting it out preserves capital.
3. How should risk and capital be allocated to reach FID?
The third decision is financing, though financing is largely a consequence of the first two. A project with a creditworthy buyer, a long-term contract and a credible delivery configuration is far easier to fund than one with the same technology and uncertain revenues. That matters more in hydrogen than in power, because there is no liquid merchant market and a producer without an offtaker has nowhere to place surplus output.
Firm, long-term offtake therefore sits at the centre of hydrogen project finance, though it does not by itself make a project bankable. The residual risks are specific and assignable: transmission delays, electrolyser performance and stack life, construction, a port terminal completed late, foreign-exchange exposure, and a carbon intensity that fails certification. Each unresolved risk shows up in the cost of capital. The strongest projects therefore structure risk before they structure financing, with technology suppliers warranting performance, contractors carrying defined construction risk, long-term renewable contracts capping power-price exposure and buyers providing volume certainty. Public guarantees and concessional finance absorb what commercial parties will not, and capital follows that allocation rather than substituting for it.
What Policy Can and Cannot Do
What policy cannot do is sign the contract. It can widen the pool of buyers and lower the cost of capital, but it cannot make a counterparty creditworthy or guarantee the volume a single project needs. A project whose economics depend entirely on the next intervention is not yet robust; the base case should rest on policies that exist today, with future mandates or carbon prices treated as upside.
India will build substantial green hydrogen capacity over the next decade. How much of it becomes a repeatable, financeable business turns on the three decisions above: a buyer who can actually pay, a plant configured around that buyer’s delivered cost and certification requirements, and each risk placed with the party able to carry it. Developers already know how to build large-scale power cheaply; the habit they must acquire is selling the molecule under contract before building the plant.
– Varun Desai ,Manager, Xynteo and Programme Lead, Energy Leap
