Becoming an Independent Power Producer in Kenya: Solar Power Licensing

Kenya’s push to add generation capacity from solar and other renewable sources has opened the door to private developers who want to build and operate their own power plants as independent power producers (IPPs). Setting up a solar IPP business in Kenya is not simply a matter of installing panels; it requires working through a licensing regime administered by the Energy and Petroleum Regulatory Authority (EPRA) under the Energy Act, 2019, negotiating a power purchase agreement with Kenya Power (Kenya Power and Lighting Company, KPLC), clearing an environmental impact assessment with the National Environment Management Authority (NEMA), and securing the site itself. Each of these steps has its own timeline and its own regulator, and getting the sequencing wrong can add months to a project. This article sets out the legal and regulatory framework a developer needs to work through to take a solar generation project in Kenya from concept to commercial operation.

The Energy Act 2019 and EPRA’s regulatory role

The Energy Act, 2019 (Act No. 1 of 2019) is the primary statute governing Kenya’s electricity, petroleum and renewable energy sectors. It was assented to on 12 March 2019 and commenced on 28 March 2019, consolidating and replacing the earlier Energy Act, 2006. The Act establishes EPRA and gives it broad authority to “regulate, monitor and where applicable, license activities in the electricity, renewable energy, petroleum and coal sub-sectors” (section 10). EPRA’s licensing powers are set out in section 11, which empowers it to “issue, renew, modify, suspend or revoke licences and permits for all undertakings and activities in the energy sector” and, importantly for anyone negotiating an offtake arrangement, to “approve electric power purchase and network service contracts for all persons engaging in electric power undertakings” (section 11(h)).

The Act defines a “licence” as any document authorising the generation, transmission, distribution or supply of electrical energy, and a “permit” as a lower-tier authorisation to carry out an activity in the energy business. The Act also commits the government to promoting renewable energy: section 75(1) requires the Cabinet Secretary to “promote the development and use of renewable energy technologies, including but not limited to biomass, biodiesel, bioethanol, charcoal, fuelwood, solar, wind, tidal waves, hydropower, biogas and municipal waste,” and section 76 establishes a Renewable Energy Resource Advisory Committee to advise on licensing and development of renewable resources. Section 73 vests unexploited renewable energy resources on or under any land in the national government, which is relevant to a developer negotiating access to a site with strong solar irradiation. Notably, the Act’s definitions section also recognises “feed-in-tariff” as a defined concept and “wheeling” as the use of another party’s transmission or distribution network to convey electricity on payment of charges, both of which matter to a solar IPP planning how it will physically deliver power to an offtaker.

Generation licensing: exemptions, permits and the full EPRA licence

The Energy Act itself does not fix a specific capacity threshold for licensing; that detail sits in subsidiary regulations made under the Act (and, before it, under the 2006 Act). EPRA’s licensing practice has for some years applied a tiered structure under the Energy (Electricity Licensing) Regulations, 2012: own-consumption generation up to a low threshold is exempt from licensing altogether, generation above that level but below a higher threshold requires only a permit, and generation above the higher threshold requires a full generation licence, with the application fee itself increasing once a project reaches roughly the 3 megawatt (MW) mark. In practice, this means a rooftop solar installation sized purely to offset a factory’s own consumption may fall outside the licensing regime entirely, while a solar farm of any meaningful scale built to sell power to the grid, which is what most IPP projects are, will fall squarely within full generation licensing. EPRA has also published draft Energy (Electric Power Undertaking Licensing) Regulations intended to update this framework for the 2019 Act; until those are finalised, the existing licensing practice continues to apply. Given how easily the applicable threshold can change and how much turns on a project’s exact capacity and whether the power is for own use or for sale, a developer should confirm the current position with EPRA directly, or with counsel, before assuming a project qualifies for a lower tier.

For an IPP-scale project, the practical route to a generation licence typically runs through several stages: an expression of interest and feasibility study submitted to the Ministry of Energy and Petroleum, negotiation of a power purchase agreement with Kenya Power, submission of that agreement to EPRA for approval under section 11(h) of the Act, registration with EPRA and a formal licence application supported by the developer’s certificate of incorporation, proof of control over the project site, environmental approvals, technical (single-line diagram and engineering) reports and audited financial statements, followed by an inspection of the facility before the licence is issued. Because the licence application generally cannot be finalised until the PPA has already been approved, the commercial negotiation with Kenya Power and the regulatory licensing track run in parallel rather than one after the other, and developers should plan financing and construction timelines accordingly.

Selling the power: PPAs with Kenya Power and Kenya’s shift away from feed-in-tariffs

For over a decade, Kenya’s principal mechanism for bringing renewable IPPs onto the grid was the feed-in-tariff (FiT) policy, first introduced in 2008 and revised in 2012 and 2021, under which the government set a standard tariff for qualifying renewable projects and Kenya Power was obliged to purchase output at that rate. That model has been overtaken by events. The government published a Renewable Energy Auctions Policy in 2021 signalling an intended shift from administratively set tariffs to competitive procurement, but as of late 2024 that auctions policy had still not been operationalised, and in the interim new PPAs with Kenya Power were effectively frozen under a moratorium on new agreements. On 13 November 2025, the National Assembly adopted an addendum report from its Departmental Committee on Energy on the cost of electricity in Kenya, which lifted the PPA moratorium and directed the Ministry of Energy and Petroleum and EPRA to implement competitive procurement of new generation capacity through an auction scheme modelled on South Africa’s Independent Power Producer Procurement Programme, to be operationalised within twelve months. The same reforms require the Attorney General to review and approve all PPAs and PPA amendments, direct EPRA to publish indicative tariffs for both feed-in-tariff and auction-based projects, and set an informal benchmark that new agreements should not exceed roughly 7 US cents per kilowatt-hour.

As a result, a developer approaching the Kenyan market today should not assume that the old feed-in-tariff route remains straightforwardly available. Some previously approved FiT-track projects appear to be continuing under transitional arrangements, but new entrants are more likely to be channelled into the emerging competitive procurement framework, with Kenya Power continuing as the principal offtaker and EPRA and the Attorney General both playing a gatekeeping role in approving the resulting contract. Because this framework was still being built out as this article was prepared, and because the practical procurement process for a new solar IPP can differ significantly depending on where a project sits in that transition, developers should treat the PPA route as the single most important item to clarify directly with the Ministry of Energy and Petroleum and EPRA before committing capital to a project.

NEMA environmental impact assessment for solar projects

Separately from EPRA licensing, a solar generation project must clear Kenya’s environmental approval process under the Environmental Management and Co-ordination Act (EMCA). Section 58(1) of EMCA requires that “any person, being a proponent of a project, shall before financing, commencing… any undertaking specified in the Second Schedule to this Act, submit a project report to the Authority,” and section 58(2) requires such a proponent to “undertake a full environmental impact assessment study and submit an environmental impact assessment study report to the Authority prior to being issued with any licence.” Energy infrastructure, including electricity generation and transmission projects, falls within the categories of undertaking listed in EMCA’s Second Schedule, so a grid-connected solar farm will ordinarily require a full EIA study and licence from NEMA before construction begins, and before EPRA will issue the corresponding generation licence. The EIA process itself involves a scoping exercise, preparation of a detailed EIA study report addressing impacts such as land use change, water use, biodiversity and decommissioning, and a public participation phase before NEMA decides whether to issue the licence, potentially with conditions. Once issued, an EIA licence generally remains tied to the project for its operational life, subject to periodic environmental audits that NEMA can require under its audit regulations. Developers should build NEMA’s timeline into the overall project schedule from the outset, since the EIA licence is typically a precondition for both the generation licence and project financing.

Securing the site: land acquisition and lease considerations

A solar farm needs a large, contiguous, well-irradiated site with secure title, and land issues are frequently the slowest part of a Kenyan solar project to resolve. Most utility-scale developers lease rather than purchase land, both because leasing preserves capital and because Kenyan law restricts land ownership by non-citizens and foreign-owned companies to leasehold, rather than freehold, interests; developers should confirm the maximum permissible lease term and any registration requirements directly against the Constitution and the Land Act before finalising a lease structure, since this is an area where the precise figures matter and are worth confirming with current legislation rather than general commentary. Whether the underlying land is held privately, by a county government, or as community land under the Community Land Act, the developer will typically need a registered lease, consent from the relevant county government for any change of user to allow energy generation on land previously zoned for agriculture or other purposes, and confirmation that the site is not subject to competing claims, easements or wayleaves. Because section 73 of the Energy Act vests unexploited renewable energy resources on or under land in the national government, and because grid connection usually requires a wayleave or easement for the transmission line linking the plant to the nearest substation, a title search and due diligence exercise on both the site itself and its surrounding access corridors should be carried out early, well before signing a lease or applying for a generation licence, so that land issues do not become the critical path item holding back financial close.