At the Olkaria geothermal complex in Kenya’s Rift Valley — the largest geothermal power facility in Africa — steam rises continuously from wellheads that tap heat stored miles underground. KenGen, the state-owned generating company, produces electricity here at an estimated cost of between $0.06 and $0.08 per kilowatt-hour. The fuel is free. The carbon emissions are negligible. The resource is baseload — generating around the clock, regardless of cloud cover or rainfall.

Kenya runs approximately 76 percent of its electricity grid on sources like this: geothermal accounting for close to 47 percent of the mix, hydro another 26 percent, the Lake Turkana wind farm adding 6 percent, and solar contributing the remainder. On most days, Kenya’s grid is cleaner than the United Kingdom’s. On a carbon intensity basis, it generates roughly 150–200 grams of CO2 per kilowatt-hour — a fraction of South Africa’s 750-plus grams or Nigeria’s approximately 450 grams.

And yet the average Kenyan household on a domestic tariff pays roughly KSh 25–28 per kilowatt-hour for its electricity once fuel cost adjustment charges, foreign exchange surcharges, rural electrification levies, and regulatory fees are factored in. That translates to approximately $0.18–0.22 per kilowatt-hour — among the highest effective tariff burdens in East Africa, and two to three times the cost of the electrons leaving the geothermal wellhead.

How does a country turn $0.07 electricity into $0.20 electricity? The answer is a lesson that every African government pursuing clean energy targets as the route to energy access needs to sit with.

The Geothermal Foundation

Kenya’s renewable energy success is not accidental. It is the product of thirty years of deliberate investment in a resource that most of the world overlooked. The Olkaria geothermal fields, first drilled in the 1980s, have been progressively expanded by KenGen through successive phases — Olkaria I, II, III, IV, and V — reaching over 800 MW of installed geothermal capacity. A further 83 MW Olkaria VI project is under development.

The resource base is enormous: Kenya sits on the East African Rift System, one of the most geothermally active zones on the planet. The country’s geothermal potential is estimated at 10,000 MW, of which less than a tenth has been developed. At current electricity demand levels — Kenya’s peak demand runs around 2,000 MW — there is enough geothermal capacity in the ground to power the country several times over.

The addition of Lake Turkana Wind Power, a 310 MW project that became Africa’s largest wind farm on commissioning in 2019, further reduced Kenya’s dependence on hydro — which is vulnerable to the rainfall variability that climate change has made less predictable — and on the legacy oil-fired thermal plants that provided backup generation during the country’s power deficit years of the early 2000s.

The generation story is, by regional standards, a success. The problem is what happens after the electricity leaves the generating station.

The Distribution Gap

Kenya Power and Lighting Company — KPLC — is the single buyer and national distributor of electricity. It sits between the generating companies that produce power and the 9 million-plus customers who consume it. And it is here that cheap geothermal power becomes expensive household electricity.

KPLC loses an estimated 22–25 percent of electricity between the generating station and the customer’s meter. This is its aggregate technical and commercial loss rate — a combination of physical losses in aging distribution infrastructure and non-technical losses from illegal connections, meter tampering, and billing inaccuracies. Every unit of electricity that disappears in the distribution system is a unit that was purchased from a generator but cannot be sold to a consumer. The cost of those lost units is borne by the paying customer base through the tariff.

Collection efficiency adds a further layer of stress. A meaningful share of electricity that is metered and billed goes unpaid — government ministries and parastatals have historically been among the largest accumulator of unpaid electricity bills. KPLC’s accounts receivable position has periodically reached levels that threaten the company’s ability to pay its own power purchase agreement obligations on time, creating a cascading arrears problem across the sector.

The combined effect of distribution losses and collection shortfalls means KPLC is effectively selling to fewer units than it buys, while its cost base — structured around the total volume purchased — remains fixed. The tariff carries the cost of the gap.

The PPA Legacy

Kenya’s distribution losses would be manageable if the generation portfolio had been structured around cheapest-cost dispatch. It was not. During the power deficits of the 2000s and early 2010s, Kenya contracted a series of independent power producers running on diesel and heavy fuel oil — thermal plants designed to add capacity quickly. The contracts were expensive but the alternative, widespread industrial load shedding, was considered worse.

Those contracts have aged badly. The capacity charges — fixed payments owed to thermal IPPs regardless of whether the plants are dispatched — remain embedded in KPLC’s cost stack even as geothermal and wind have made the thermal plants largely redundant. Kenya Power is effectively paying for insured capacity it does not need on most days. The capacity costs flow through to the tariff via fixed-cost recovery charges that have proved politically and contractually difficult to restructure.

The Energy and Petroleum Regulatory Authority and successive governments have identified PPA renegotiation as a priority for reducing the consumer tariff burden. Progress has been made — some contracts have been restructured, others have expired without renewal — but the pace has been slower than the policy intent. The remaining legacy thermal portfolio continues to inflate the base tariff structure that EPRA’s quarterly review mechanism is calibrated around.

What EPRA’s Quarterly Review Can and Cannot Fix

The Energy and Petroleum Regulatory Authority conducts quarterly electricity tariff determinations, adjusting consumer prices for changes in fuel costs, foreign exchange movements, and the weighted average cost of generation across the dispatch portfolio. The mechanism was designed to protect KPLC’s financial viability while preventing the accumulation of regulatory cross-subsidies that have historically triggered utility insolvency across the continent.

What the quarterly review cannot address is structural. Distribution loss rates, thermal PPA legacy charges, and collection efficiency are operational and contractual realities, not quarterly variables. The EPRA formula adjusts margins around a cost base that is set by investment decisions made over decades. Reducing the consumer tariff sustainably requires reducing the cost base — which requires loss reduction investment, PPA restructuring, and improved collection — not a regulatory formula revision.

The government’s own Kenya Electricity Sector Investment Prospectus acknowledged this in its 2024 update: the pathway to lower and more competitive electricity tariffs runs through distribution modernisation, not generation expansion. Kenya has been expanding generation successfully for two decades. Distribution investment has lagged.

What Kenya’s Experience Tells Africa

Kenya is the continent’s best-developed test case for a question that is about to become urgent across Africa: what happens after you solve the clean generation problem?

The climate finance architecture — the Just Energy Transition Partnerships, the Mission 300 initiative, the multilateral development bank clean energy facilities — is predominantly organised around generation: solar plants, wind farms, geothermal development, off-grid systems. Generation is the visible, bankable, headline-friendly part of the energy transition. A 255 MW solar plant in South Africa or a 300 MW wind farm in Egypt produces a number, a financial close announcement, a commissioning event.

Distribution infrastructure does not produce those moments. But it is where the consumer experience lives. A household connected to a grid that loses 25 percent of its electricity in transmission and charges foreign exchange surcharges on imported fuel-oil backup capacity is not experiencing cheap geothermal power. It is experiencing the full accumulated cost of a system that has not been reformed end to end.

Kenya’s electricity sector has done what most of Africa is still trying to do. It has cleaned its generation mix at scale, ahead of the rest of the continent, at reasonable cost. The lesson from what came after is not an argument against clean generation. It is an argument for treating distribution reform — loss reduction, billing modernisation, PPA portfolio management, collection system investment — as an equal priority, funded and tracked with the same rigour that the continent’s generation ambitions receive.

The climate finance community counts gigawatts. It should also be counting kilowatt-hours delivered, billed, and paid — because the gap between those three numbers is where Africa’s energy access story will be won or lost.