South Sudan’s power link with Uganda: what Kenya’s experience can teach

The question

What should South Sudan learn from Kenya’s electricity imports as it develops its own connection to Uganda?

Electricity connectivity was again on the agenda when President Yoweri Museveni met a South Sudanese delegation led by Trade and Industry Minister Dr Labanya Margaret Mathya on 14 October 2026.^[5] The immediate question is how that political support will translate into service for consumers.

Uganda technically launched its component of the South Sudan–Uganda Power Interconnection Project on 24 September 2026. Reported next steps included procurement, safeguards and land acquisition. The launch did not mean the new line had begun delivering electricity.^[1]

The proposed high-voltage link between Olwiyo and the Juba area offers a route into regional power trading. But its success should ultimately be judged at the customer’s meter, not only at the border.

The assessment

South Sudan should develop the interconnection together with local distribution, a credible pricing system and clear operating agreements. Building the transmission line without those arrangements risks bringing electricity closer to consumers without making it affordable or dependable.

Kenya provides a useful comparison because regional imports are already part of its supply. It also provides a warning: importing power and fixing domestic electricity service are different tasks.

Kenya has a larger and more developed electricity system. Its experience offers lessons about managing imports, rather than a forecast of South Sudan’s future costs or performance.

What Kenya’s experience establishes

For the year ended 30 June 2026, Kenya’s regulator reported that imports supplied 12.19 per cent of the electricity mix. Deliveries through the Ethiopian Electric Power interconnection amounted to 1,577.66 gigawatt-hours.^[2] A gigawatt-hour measures energy delivered over time; it is not the same as a line’s rated capacity.

These figures establish that cross-border supply is a practical resource, not merely a diplomatic ambition.

Yet the same report recorded system losses of 21.38 per cent and an average sustained interruption length of 3.23 hours per incident, above the regulatory benchmark.^[2] These are national system indicators. They do not show that imports caused outages or losses.

The lesson is narrower and stronger: regional electricity trading can coexist with serious domestic service problems. Access to another country’s generation does not remove the need to maintain wires, meters and local networks.

From the border to the business

The project’s official description includes substations, distribution lines and last-mile connections, alongside operating arrangements, tariff studies and technical capacity-building.^[3] Delivering these components together will matter as much as completing the main line.

A high-voltage line moves electricity over distance. Substations and distribution networks then carry it at usable voltages to homes, shops, clinics and workshops. A settlement near a transmission route does not automatically receive a connection.

That distinction should shape the investment plan. Connection charges, household wiring, meters and local transformers can determine who benefits first. A shopkeeper unable to afford the initial connection cannot use a lower energy price.

The distribution programme should therefore identify intended service areas, connection costs, responsible institutions and funding. It should explain which investments are included in the interconnection project and which depend on separate financing.

A lower purchase price is not a lower bill

Regional trading is attractive partly because it can replace more expensive generation. But the price paid for imported electricity is only one part of the final cost.

Consumers also fund transmission, distribution, maintenance, metering and other authorised charges. If energy is lost or supplied without being billed, the utility still needs money to meet its obligations.

Before promising savings, South Sudan should publish a cost-of-service explanation: the import price, network costs, expected losses, taxes and any subsidy. It should distinguish one-off connection charges from recurring bills.

The currency of the supply contract also matters. If electricity is purchased in foreign currency but bills are paid in South Sudanese pounds, exchange-rate changes could increase costs. The tariff framework should explain how any such risk would be shared among the utility, government and consumers.

Subsidies may help low-income users connect or maintain essential consumption. Broad subsidies can also consume money needed for maintenance. Any support should identify who qualifies, who pays and how the commitment will be funded.

Trading needs rules as well as goodwill

The two countries already have a history of formal cooperation. A power sales agreement was signed in June 2023, and public reporting also described a separate utility agreement for distribution in Nimule and Kaya.^[6] Those earlier arrangements should be distinguished from the new high-voltage project.

Regional institutions have continued coordinating implementation with the two utilities and South Sudanese authorities.^[4] That cooperation matters because construction on one side of the border cannot substitute for readiness on the other.

The operating framework should make clear how much supply is guaranteed; how interruptions are communicated; who pays for repairs; what happens if a payment is late; and how disputes are resolved. Publishing these arrangements would help consumers and businesses understand the service they can expect.

Shared operating rules can make cooperation more durable than personal assurances. But even a well-written contract cannot eliminate equipment failures, transmission damage or a supplier’s competing demands.

South Sudan should therefore assess the interconnection alongside domestic generation, solar systems, storage and suitable backup supply. Diversification is useful when it protects essential service at a justified cost.

The strongest counterargument: build supply first

A serious objection is that demanding a complete commercial and institutional system before construction could delay urgently needed electricity. A major connection can unlock demand, attract businesses and make later investment worthwhile.

That argument has force. South Sudan should not wait for perfect institutions before building useful infrastructure.

The answer is parallel preparation. Construction, distribution planning, tariff analysis and operating agreements can advance together, with clear milestones before energisation.

There is also a geographical trade-off. Grid expansion may serve concentrated demand efficiently, while distant communities may benefit sooner from smaller systems. Supporting the regional link should not become a reason to postpone every off-grid investment.

What would demonstrate progress?

Before electricity flows, readers should look for contract awards, completed safeguards, compensation arrangements, substation milestones and a realistic commissioning schedule.

Once service begins, the indicators should change: electricity actually delivered; active customer connections; the full cost of a standard bill; outage frequency and duration; losses; and whether clinics and businesses receive the service promised.

Those measures should retain their dates and coverage. A result from Juba should not be presented as national electrification.

Kenya shows that regional power trade can become operationally significant without resolving every domestic weakness. South Sudan’s opportunity is to plan for both sides of that lesson: secure the electricity and build the institutions that turn it into a useful public service.