Kenya reopened to new Power Purchase Agreements in November 2025 after a moratorium of nearly three years. In January 2026, EPRA revoked its allowed-return guidelines and the geothermal benchmark tariff, signalling a broader reset of how project economics will be priced going forward. Foreign sponsors evaluating Kenyan generation, transmission, or distribution projects are entering a market that is structured but in motion. The questions they answer first will shape whether their project clears regulatory review, attracts financing, and survives the long horizon a power asset demands. This article sets out those questions and explains why each one carries asymmetric downside if it is left to be answered later.

At a glance: Foreign sponsors entering Kenya’s energy sector in 2026 should answer key legal questions before committing capital. Kenya has reopened to new Power Purchase Agreements, but the pricing framework has changed, beneficial ownership disclosure is now a serious consideration, and projects must be structured carefully around licensing, land rights, ESIA approvals, offtake terms, tax, treaty protection, and exit planning. The strongest projects are built with legal durability from the start, rather than corrected after financing, regulatory, or community problems appear.

Why these questions matter more in 2026 than they did three years ago

The Kenyan energy market has moved through a difficult window. The PPA moratorium imposed in September 2021 froze new private offtake arrangements with Kenya Power. Parliament lifted that freeze in November 2025 and approved a new currency framework allowing PPAs to be denominated in Kenya shillings, foreign currency, or a hybrid of the two. EPRA then revoked the existing investment return and geothermal benchmark guidelines in January 2026.

What that means for a sponsor entering today: the procedural reopening is real, but the pricing framework that determined returns on past projects has been withdrawn. New projects will need to be justified on their own commercial logic rather than slotted into a published tariff table. Beneficial ownership disclosure has also become a structural requirement. Parliament directed the Business Registration Service to publish the full shareholder and beneficial owner list of all IPPs within six months of the November 2025 decision. Sponsors who structured past Kenyan investments behind layered holding companies need to understand that their ownership is now expected to be visible, and to plan accordingly.

The questions below were always relevant. They are more consequential now because there is less of a default answer to fall back on.

Question 1: What entity will hold the investment, and what does that entity actually own?

Foreign sponsors typically enter Kenya through a holding company in a treaty-favoured jurisdiction such as Mauritius, the Netherlands, the UAE, or Singapore. The Kenyan project itself must usually be held through a Kenyan-incorporated project company, particularly where the project agreement is procured under the Public Private Partnerships Act. The Energy Act also requires a foreign entity holding a licence to establish and maintain a Kenyan office for the duration of that licence.

The question to answer before incorporation is sharper than “where should the holding company sit?” It is: which protections, treaty rights, tax outcomes, and disclosure exposures attach to the ownership chain we are about to build? A Mauritius holding company will not give an investor the same treaty protection as a Dutch holding company. A UAE structure does not produce the same withholding profile as a Singapore one. The cost of structuring around the wrong jurisdiction is rarely visible at the start. It becomes visible when a dispute arises, when profits are repatriated, or when the project is sold.

With the new beneficial ownership disclosure requirement, the secondary question is whether the sponsor is comfortable with the local visibility of their ownership chain. Sponsors who rely on undisclosed nominees or layered offshore vehicles for reasons unrelated to ordinary tax planning will find the new regime uncomfortable. Sponsors with clean ownership should treat disclosure as a non-issue and structure for substance instead.

Question 2: Under what regulatory pathway, and on what tariff logic, will this project actually be approved?

EPRA is the central regulator under the Energy Act 2019. Generation licences run for 25 years and distribution licences for 20 years. The licensing pathway itself is not the part most sponsors get wrong. The part that creates risk is tariff logic.

Before January 2026, EPRA published an allowed return on investment methodology and benchmark tariffs for technologies such as geothermal. Those have been withdrawn. New projects will need to negotiate their tariff on the basis of project-specific economics. That changes what a sponsor needs to bring to the table on entry. A defensible financial model, a transparent cost stack, and a clear explanation of risk allocation between the IPP and Kenya Power will matter more than a comparison to a published benchmark.

The licensing question itself is straightforward. Foreign ownership of generation, transmission, distribution, and supply is permitted, and the procedural route is well-defined. What is harder to answer is: under what offtake and tariff framework will our project actually clear, and what does that framework require us to disclose, justify, and commit to upfront?

Question 3: Is the land position genuinely secure, or only apparently secure?

Land delays more Kenyan energy projects than any other single issue. The legal terrain has several layers. The Land Control Act requires Land Control Board consent for transactions involving agricultural land, which most utility-scale projects sit on. The Community Land Act governs land held by communities and creates expectations of consultation and consent that are stricter in practice than many sponsors anticipate. The National Land Commission handles compulsory acquisition where the state is acquiring land for project purposes. The Energy Act 2019 requires national and county governments to facilitate land acquisition for energy infrastructure, but the practical experience of recent geothermal and wind projects shows that statutory facilitation does not eliminate community-level objections.

A title search is the beginning of a land position, not the whole of it. Sponsors should ask whether:

• The land is freehold, leasehold, or community land, and whether the chain of title can be verified beyond the immediate seller.
• Any encumbrances, caveats, or pending succession matters affect the parcel.
• Land Control Board consent is required, and whether the proposed transaction will satisfy the board.
• Community consultation under the Community Land Act has been carried out in a way that will survive challenge.
• Wayleaves and easements for evacuation infrastructure have been secured separately from the project site.

The cost of an unresolved land issue is rarely paid in legal fees. It is paid in months or years of project delay during the most expensive part of the development cycle.

Question 4: Will the ESIA satisfy NEMA, lenders, and the affected community?

The National Environment Management Authority approves the Environmental and Social Impact Assessment for energy projects. NEMA approval is necessary, but lenders and communities apply their own standards in parallel. Development finance institutions and commercial banks following the Equator Principles will apply IFC Performance Standards. Communities will apply their own expectations, which often include Free, Prior and Informed Consent for projects affecting indigenous land.

Recent experience in Suswa and Menengai shows that ESIA approval from NEMA does not insulate a project from community resistance if FPIC has not been applied properly. The legal cost of this gap is low. The project cost can be substantial: blockades, litigation, suspended construction, and reputational exposure that follows the sponsor into the next jurisdiction.

The right question at the entry stage is whether the ESIA process will satisfy all three audiences, or only the regulator. If the answer is only the regulator, the project is carrying a risk that will appear later, usually at the worst time.

Question 5: What offtake, in what currency, and on what conditions?

Most Kenyan IPPs sell into Kenya Power under a long-term PPA. The November 2025 currency framework allows PPAs to be denominated in shillings, foreign currency, or a hybrid. The hybrid model is the one most foreign-financed projects will need: local operating costs and taxes paid in shillings, debt service paid in the currency of the underlying financing.

The legal questions to answer before commitment include:

• What tariff structure will EPRA approve in the absence of the revoked benchmark guidelines?
• What is the indexation logic for foreign currency components, and how is currency convertibility addressed?
• What are the deemed-energy, force majeure, and political risk provisions, and do they match the risk profile lenders require?
• Is a government Letter of Support, sovereign guarantee, or partial risk guarantee available for the project, and what conditions attach to it?
• What step-in rights will lenders have, and what direct agreements with Kenya Power will support them?

A PPA that satisfies the sponsor but not the lender will not close. A PPA that satisfies both but not EPRA will not be signed. Sponsors who treat the PPA as a late-stage negotiation underestimate how much of the project’s economics are set by its terms.

Question 6: What treaty protection, if any, applies to this investment?

Kenya is party to several bilateral investment treaties, with varying provisions on fair and equitable treatment, expropriation, free transfer of funds, and investor-state dispute settlement. Whether a sponsor’s investment is covered by a BIT depends on the jurisdiction of the qualifying investor entity in the ownership chain, not on the sponsor’s ultimate parent.

This is one of the questions most often answered too late. A sponsor who incorporates a Kenyan project company through a holding vehicle in a jurisdiction without a Kenya BIT, when a small structural change would have brought the investment under treaty coverage, has reduced their recourse against host state action without any commercial benefit. The same is true of arbitration clauses in the underlying project documents. A vague arbitration clause is a contingent liability priced at zero on the way in and at full project value when something goes wrong.

The question to answer at the structuring stage: if Kenya, or a Kenyan state entity, took an action that materially harmed the investment, what is the recourse, in which forum, under which law, and with what enforcement reach?

Question 7: What does the tax architecture look like across the holding chain?

Kenya offers incentives for renewable energy investment, including VAT and customs exemptions on qualifying equipment and investment deductions for capital expenditure. Withholding tax on PPA payments, dividend distributions, interest, and management fees can erode returns if the holding structure is poorly chosen. Kenya is party to double taxation agreements with several jurisdictions; the holding company location should be evaluated against those agreements rather than in isolation.

Two specific questions need direct answers at the structuring stage:

1. What is the after-tax internal rate of return at the holding level, after withholding, transfer pricing, and corporate tax in each jurisdiction in the chain?
2. How will intra-group services, financing, and royalty arrangements be priced, and will those prices survive scrutiny under Kenyan transfer pricing rules and the rules in the holding jurisdiction?

A project that is bankable pre-tax and marginal after-tax will create friction with investors at the first board review. The tax question is best answered before incorporation.

Question 8: How does the sponsor exit, and what does the next buyer need to see?

Exit is the question most sponsors are happy to defer. It should be answered at entry, for a practical reason: the next buyer will perform due diligence on the legal foundations the original sponsor put in place. Weaknesses in title, licensing, ESIA, PPA, or corporate structure that were tolerable during development will reduce the purchase price or kill the sale.

The exit questions to address at the structuring stage include: what consents are required for share transfer at the project company level, at the holding company level, and under the PPA and licence? What capital gains tax applies on an exit, and in which jurisdiction? Are there change-of-control provisions in the offtake or licensing arrangements that could be triggered by a sale? What audit trail will demonstrate that the project was developed in compliance with NEMA, FPIC, and lender standards, so that the next buyer does not discount the price for legacy risk?

Sponsors who answer the exit questions on the way in build assets that command stronger prices on the way out.

The meta-question underneath all of these

Underneath the eight questions above is a single question that captures the rest: is this project legally durable enough to survive its own success?

Most legal failures in Kenyan energy projects are architectural. The compliance steps were followed; the structure underneath was wrong. A licence was obtained, but under a tariff framework that no longer applies. Land was secured, but the community consent was thin. A PPA was signed, but the currency framework shifted. A holding structure was set up, but it sits outside any treaty protection. The project moved fast through development, and then encountered a problem that should have been answered at the start.

The questions above exist to protect the value of a project at the point where its value is still mostly potential. By the time those questions become urgent, the cost of answering them well has multiplied.

A closing note

Kenya is an increasingly structured market for energy investment. The reforms of late 2025 and early 2026 have made the structure more transparent and, in some respects, more demanding. Foreign sponsors who treat Kenya as a market to be navigated rather than as a market to be entered tend to build projects that survive. The questions above are the ones that mark the difference between the two approaches.

WAREN Law Advocates LLP advises foreign sponsors, lenders, operators, and project counterparties on the legal architecture of energy and extractives projects in Kenya, with particular attention to investment structuring, regulatory pathways, land and community risk, PPA and offtake arrangements, and treaty protection.

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