Kenya is celebrated globally as a renewable energy leader, with at least 90 per cent of its electricity generation coming from clean sources such as geothermal, wind, hydro, and solar.
Yet behind this success story lies a sobering contradiction: millions of Kenyans remain either unconnected to the grid or unable to afford the electricity that flows through it.
According to the Tracking SDG 7 2024 report, an estimated 12.9 million people still live without grid electricity.
For many of those connected, the burden of unaffordable bills and erratic service makes reliable access elusive. For these communities, the much-heralded green energy revolution has not brought relief; it has left them behind.
This reality raises difficult questions about the fairness of Kenya’s transition. Globally, there is a growing consensus that climate solutions must be pursued through a “just transition,” one that is equitable, inclusive, and leaves no one behind.
In Kenya, however, clean power that is unaffordable becomes exclusionary.
The Last Mile Connectivity Project, launched in 2013 to subsidise grid infrastructure for low-income households, raised access from 40 per cent to 79 per cent. Despite this achievement, Kenya’s electricity remains the most expensive in East Africa. The paradox is clear: how can a country so rich in renewable energy continue to struggle with widespread energy poverty?
Why hasn’t abundance translated into affordability?
“Kenya’s electricity remains comparatively expensive, largely due to the structure of its generation mix. The price the consumer sees is not just the generation price,” explains George Aluru, Chief Executive Officer of the Electricity Sector Association of Kenya (ESAK).
“It includes pass-through costs like monthly fuel charges, inflation adjustments, forex levies due to the devaluation of the shilling, and several statutory levies such as VAT, the Water Resource Authority levy, and the EPRA levy.”
Generation typically accounts for 60–70 per cent of the final tariff. The rest is a patchwork of extra charges.
Kenya’s generation mix is dominated by geothermal, hydro, wind, solar, and thermal technologies, all capital-intensive and technically complex.
Geothermal, for instance, is a reliable base-load source, but requires massive upfront investment and lacks the economies of scale of coal or gas plants in countries like South Africa or Egypt. Wind and solar, while clean, are intermittent and require costly thermal backup to stabilise the grid.
“At 7 p.m., we lose about 443 megawatts from solar and must switch on expensive thermal plants to maintain stability,” Aluru explains.
The weight of power contracts
A major driver of high tariffs lies in the Power Purchase Agreements (PPAs) signed between the government and Independent Power Producers (IPPs).
Isaac Ndereva, a billing expert and Executive Director of the Electricity Consumer Society of Kenya (ELCOS), argues that many contracts were negotiated without public participation and heavily favour investors.
“Some IPPs sell power at two or three times the cost of KenGen, even when operating from the same geothermal fields,” he says.
Most of these contracts are denominated in US dollars, meaning currency fluctuations directly hit consumers through forex adjustments. Worse, take-or-pay clauses compel Kenya Power to buy a fixed amount of electricity regardless of demand. Consumers end up paying for unused power, effectively subsidising investor security.
While these clauses were designed to attract foreign capital, their long-term effect has been to shield IPPs from market risks while transferring costs to the public.
Aluru, however, stresses the complexity: “The cost burden borne by consumers is not simply a matter of efficiency but a reflection of how the entire ecosystem, from financing and regulation to procurement, is structured to front-load risk and delay value realisation.”
Getting an IPP project from concept to operation takes between eight and twelve years, during which developers spend heavily on feasibility studies, land, environmental assessments, and early infrastructure.
“By the time a project reaches financial close, developers have already sunk millions into preparatory work, costs that must be recovered through the tariff,” he explains.
The high cost of capital compounds the problem. In Kenya, project financing carries interest rates of 18–20 per cent, compared to 5–7 per cent internationally.
“We are financing long-term infrastructure with short-term, expensive debt,” Aluru says. “That mismatch inflates risk and makes electricity more expensive before a single kilowatt is generated.”
Losses, levies, and inefficiencies
Systemic inefficiencies also weigh heavily. “Kenya Power loses 23 per cent of all the electricity it purchases, with 13 per cent lost to theft and 10 per cent to technical transmission losses. These losses amount to over KSh30 billion annually and are directly passed on to consumers,” Aluru states.
“If someone is stealing electricity, paying consumers are the ones bearing the cost.”
In addition to theft, outdated infrastructure and overloaded transformers add to technical losses.
Levies built into bills remain equally contentious. The EPRA levy funds the regulator but is paid by consumers. Ndereva argues: “If we’re paying their salaries, we should also have a say in appointing the regulator.”
The Water Resources Management Authority (WARMA) levy, once five cents per kilowatt-hour, has risen to nearly two shillings. It is supposed to fund hydropower catchment conservation, yet areas like the Aberdare Ranges remain privately owned and poorly managed.
“It looks more like a revenue collection tool than an environmental protection mechanism,” Ndereva asserts.
The 5 per cent Rural Electrification Authority levy also raises questions. Many rural connections are already funded through government and county budgets or through the Constituency Development Fund. VAT further compounds consumer burdens, especially when applied to other charges like the fuel cost adjustment. This layering creates a form of double taxation.
Billing practices only deepen frustration. When meters are left unread for long periods, Kenya Power issues estimated bills that underestimate usage. Later, when meters are updated, catch-up charges are billed at current, usually higher, tariffs, regardless of when the electricity was consumed.
“If I consumed electricity in 2020, do not bill me at 2024 prices,” Ndereva insists. “It’s unfair and erodes consumer trust.”
Calls for reform
To fix systemic issues, Aluru advocates for a fundamental policy shift from a central monopoly to a competitive, market-based energy system. Kenya already has draft regulations supporting competitive procurement, net metering, open transmission access, and a wholesale electricity market.
A functioning wholesale market, he explains, would allow power to be traded like a commodity, with prices set hourly based on demand and supply. This model could attract investment, increase competition, and lower prices, but only if legacy contracts and inefficiencies are addressed.
Aluru also highlights the potential of captive power generation, where consumers such as malls, factories, or communities install renewable systems and either use the power on-site or “wheel” it to another location via the grid.
“You’re not interacting with Kenya Power. You’re generating solar on your rooftop or plot and selling directly to your neighbour or another business,” he says.
Still, reforms must be coupled with investment-friendly policies. Aluru criticises new tax proposals that introduced VAT on solar and geothermal equipment and reduced the allowable period for tax loss recovery.
“The first five to eight years of a power plant are loss-making,” he explains. “If I cannot carry forward those losses, I have to raise project premiums, and that cost ends up on the consumer’s bill.”
Licensing delays, which can stretch up to 12 years, further inflate costs. “You’re paying staff, leasing land, and conducting studies without knowing whether the project will ever be approved,” Aluru says.
He also laments scepticism toward local investors. “We are more comfortable when a foreign company owns a power plant than when a Kenyan does,” he observes. Local ownership, he argues, could lower costs and increase resilience.
Aluru further points to private-sector interest in financing transmission infrastructure through partnerships with KETRACO. Such arrangements could inject capital, expand the grid, reduce technical losses, and extend access to remote areas.
The off-grid equity gap
Patrick Tonui, Head of Policy and Regional Strategy at GOGLA, stresses the inequities between on-grid and off-grid users. Off-grid communities, typically remote and low-income, bear far higher costs because they shoulder the full expense of access.
“Grid-connected users benefit from government-funded poles and transformers,” Tonui says.
He advocates targeted subsidies and stable tax policies. Complete solar kits may be duty-free, but inverters and batteries are often taxed, making systems unaffordable.
“We fight every year to keep VAT exemptions on solar products in the Finance Act,” he notes. “Investors cannot plan when policy changes annually.”
Tonui points to the Kenya Off-Grid Solar Access Project (K-OSAP), which subsidises productive energy uses in remote areas, as crucial for rural development. He warns against over-reliance on cost-reflective tariffs in such regions: “If every consumer had to pay the full cost of infrastructure, access would be impossible.”
Counting the costs
Andrew Amadi, an energy transition expert, further dissects the pricing puzzle. Of the KSh28.69 paid per unit in June, KSh19.08 now goes to Kenya Power, making the base tariff the largest component after the 2023 reforms.
The Fuel Cost Charge, while reduced, remains volatile and poorly communicated, particularly to prepaid users. “Consumers end up getting fewer units for the same money and do not know why,” Amadi says.
He highlights stark markups between generation costs and consumer rates. “Wind power from Ngong Hills costs Kenya Power about Sh10 per kilowatt-hour but is sold at nearly Sh19. Hydropower costs as little as Sh2–3, yet consumers still pay Sh19.”
Rather than building new plants, Amadi argues, Kenya should focus on reducing losses. He also champions solar self-generation: “If I install solar, I pay around Sh5 per kilowatt-hour.”
Many commercial users are already shifting to third-party solar providers, cutting their costs from Sh26 per unit to as little as Sh15. Kenya Power, he warns, is losing industrial clients, a trend that could deepen its financial woes and push household tariffs even higher.
Amadi proposes privatising system operations, not assets, to improve efficiency. Private firms could manage sections of the grid, reduce losses, and share savings with consumers. Community-led solutions, such as aggregating meters in gated estates and billing at higher voltage levels, could also lower costs by at least KSh6 per kilowatt-hour.
A paradox in need of resolution
Kenya’s renewable energy story is often told as a triumph; clean sources dominate the energy mix, and access has expanded significantly in a decade. But beneath the statistics lies exclusion, inefficiency, and mounting public frustration.
Electricity that is clean but unaffordable remains a barrier. Power that is abundant yet inaccessible remains unjust.
Kenya must now align its renewable leadership with inclusive, transparent, and fair energy delivery.
