Structuring Green Hydrogen Offtake and Project Agreements in Kenya

Kenya has more announced green hydrogen activity than almost any other African country outside Namibia and Egypt: a KES 17 billion electrolysis project with German backing, an $800 million KenGen joint venture with China’s Kaishan Group producing green ammonia fertiliser at Olkaria, and, by one ministerial count, fifteen project proposals already through EPRA’s initial approval stage. What the sector does not have is a hydrogen law, or a standard offtake contract. Anyone structuring one of these deals is working from general commercial law layered onto an energy licensing regime that was not written with hydrogen in mind.

There Is No Hydrogen Act, and EPRA Is Regulating by Extension

The Energy Act, 2019 does not mention hydrogen. Its renewable energy promotion clause, section 75(1), lists biomass, biodiesel, bioethanol, solar, wind, tidal, hydro and biogas, not hydrogen or its derivatives. The Energy and Petroleum Regulatory Authority is instead relying on its general licensing powers, the authority under section 11(a) to license “undertakings and activities in the energy sector” and under section 11(h) to approve power purchase and network service contracts, and treating a green hydrogen plant as a licensable energy undertaking by extension rather than under an express statutory category. In May 2024, EPRA published its own Guidelines on Green Hydrogen and its Derivatives to fill that gap. The Guidelines are administrative guidance, not gazetted subsidiary legislation, a distinction worth keeping in mind when assessing how binding any individual requirement actually is.

What EPRA’s Guidelines Actually Require on Offtake

The Guidelines do not prescribe a template offtake agreement, a regulated tariff, or mandatory contract terms. What they impose is a disclosure and reporting regime built around the project approval timeline. A developer’s initial Expression of Interest must state the proposed offtaker of the green hydrogen and whether the use is domestic, export, or the developer’s own consumption. After approval, the developer has 24 months to complete a feasibility study, with a sub-milestone at 18 months requiring the study to address project financing and the proposed offtake or transformation route. Once producing, the developer owes EPRA an annual accounting of hydrogen produced and its offtakers. Separately, the Guidelines set a well-to-gate emissions ceiling of 1.0 kgCO2e per kg of hydrogen for the “green” classification, a specification that is likely to end up as a warranty clause in any offtake agreement rather than just a licensing formality. None of this amounts to a regulated offtake framework. It is a disclosure checkpoint layered onto the licensing process, which means the substance of who buys the hydrogen, at what price, and under what remedies, is left entirely to ordinary contract negotiation.

Powering the Project Runs Through a Separate, More Developed Regime

Where EPRA’s Guidelines are thin, Kenya’s electricity market regulations are not. A hydrogen producer without its own generation needs to get renewable power to its electrolyser, and the Guidelines themselves point to the existing wheeling mechanism for this: a developer may “purchase renewable energy electricity by entering into a power purchase agreement with another market player” and have that power wheeled across the grid. The operative rules sit in the Energy (Electricity Market, Bulk Supply and Open Access) Regulations, 2024. Regulation 7 requires transmission and distribution licensees to provide non-discriminatory open access on payment of wheeling charges. Regulation 33 sets minimum load thresholds for open access, not less than 1MVA at distribution level or 10MVA at transmission level, a threshold an industrial-scale electrolyser is likely to clear. Bulk supply contracts between licensees follow a prescribed format under regulation 27, with the Authority required to respond to an application within 30 days under regulation 20. This is the framework doing the real legal work behind a hydrogen project’s power supply, more so than any hydrogen-specific instrument.

The Real Deals, and What Is Actually Confirmed

Public reporting describes at least two KenGen-linked green hydrogen and ammonia initiatives at Olkaria: a roughly KES 17 billion, German (KfW)-backed electrolysis project reported in talks as of May 2025, and the $800 million KenGen-Kaishan joint venture, groundbreaking held 3 November 2025, using 165MW of geothermal power to produce up to 480,000 tonnes of fertiliser a year. Whether these are the same project described differently by different sources, sequential phases, or genuinely separate ventures is not resolved in public reporting, and we would not advise treating the figures as interchangeable. Fortescue’s proposed Kenya green ammonia project, using geothermal power, has been reported at the government-to-company framework stage rather than as a signed, financially closed project agreement. What all of this shows is a market where deals are being individually negotiated and structured case by case, exactly as the absence of a standard contract would predict.

Where the PPP Act Fits, and Where It Does Not

Kenya’s Public Private Partnerships Act, 2021 establishes the procedure for private-sector participation in infrastructure and development projects, and sets minimum obligations for parties to a project agreement. Where a state corporation such as KenGen is a project party, the Act is a live consideration for how the transaction is structured and approved, including the privately-initiated proposal route under sections 40 to 43 where a developer rather than the state initiates the project. Whether the Act applies as a matter of law to any specific green hydrogen transaction depends on the structure of that transaction, principally whether a public entity is genuinely a contracting party in a way that triggers the Act, and this is not a question with a blanket answer. It should be assessed on the facts of each deal rather than assumed either way.