The missing span

EXECUTIVE THESIS

The most important part of an interconnector may not be the line

Africa's power pools are commonly described through their visible assets: kilometres of high-voltage line, substations, transfer capacity and commissioning dates. Those measures matter. They do not, however, establish that a regional electricity market is functioning.

An interconnector creates an option to trade. Turning that option into reliable electricity requires a longer chain: completed and synchronised infrastructure; operating rules and transmission tariffs; dispatch and congestion management; creditworthy buyers; payment and foreign-exchange settlement; sufficient bids; national-grid capacity; distribution equipment; customer connections; and maintenance. Every link has to work at the same time.

This distinction is becoming more important because the physical map is filling in. More than 4,000 kilometres of high-voltage transmission now connect the grids of 15 West African countries, according to the World Bank. Yet only about 8% of the region's electricity is traded across borders.[1] In Southern Africa, where a competitive platform has operated for years, bilateral contracts still dominate. In Eastern Africa, substantial bilateral trade coexists with no recorded energy on the central market platform as of May 2026.[3][4]

The evidence does not support a story of failure. It shows something more useful: regional power integration has moved from a construction problem to a delivery-system problem. The investment question is no longer simply whether to fund a line. It is whether the corridor's physical, commercial, financial and last-mile layers can reach readiness together.

STONECOMMS ORIGINAL SYNTHESIS

StoneComms proposes a Corridor Readiness Ledger for that decision. It tests seven linked conditions: physical completion; synchronisation and operations; market rules; settlement and payment security; available supply and demand; national and local delivery; and safeguards, maintenance and governance. The corridor should be judged by its weakest span, not its most advanced component.

A POWER LINE IS CAPACITY, NOT A TRANSACTION

Four outcomes that are often collapsed into one

The language of regional electricity projects regularly moves too quickly between four separate outcomes.

The first is physical interconnection: a line and its substations can carry power. The second is operational coordination: systems can remain stable while power crosses borders. The third is commercial exchange: sellers and buyers can contract, schedule, meter and settle a transaction. The fourth is public delivery: the imported electricity is carried through national networks, reaches a customer, is affordable enough to use, and generates revenue for the utility.

Progress at one layer does not prove progress at the next. Megawatts of technical transfer capacity are not megawatt-hours traded. Matched bids are not delivered energy. Lower wholesale purchase costs are not automatically lower retail tariffs. A village crossed by a transmission right-of-way is not necessarily connected.

The distinction matters because headline figures tend to come from the easiest layer to count. Steel, towers and substations can be inspected. Market liquidity, settlement discipline, dispatch performance, distribution readiness and affordability are harder to compress into a ceremonial milestone.

West Africa illustrates the movement between these layers. The West African Power Pool launched the first phase of its regional market in 2018 around bilateral transactions. Regional market rules and procedures were approved in November 2025, followed by a transmission-tariff methodology in March 2026. In July and August 2026, WAPP still described the Day-Ahead Market as preparing for or approaching launch, while work continued on permanent synchronisation and foreign-currency settlement.[6][7]

There is real progress here. A four-hour synchronous test connected all 15 national grids in November 2025, and cross-border flows helped reduce deficits during a difficult June 2026 period of high demand, outages and weak seasonal hydro.[8][9] But a trial, a bilateral contract and a liquid day-ahead exchange are not the same institution. The market becomes useful only when the operational and commercial layers work repeatedly, including on stressed days.

THE CORRIDOR THAT REVEALS THE PROBLEM

North Core's different percentages describe different things

The WAPP North Core project is designed to link Nigeria, Niger, Benin and Burkina Faso. The World Bank's June 2025 restructuring paper put the full project cost at US$640.2 million and described 875 kilometres of 330 kV line, additional 225 kV works, substations, fibre and control systems. Its technical design could handle up to 605 MW.[10]

The project also demonstrates why corridor reporting needs more precision. An African Development Bank implementation report published on 13 September 2026 said the AfDB-financed Burkina Faso package was 95% complete and undergoing tests, with commissioning planned for July 2026.[11] That statement is not evidence that the whole Burkina transmission segment, much less the four-country corridor, had entered commercial service. Separate World Bank-financed line lots cover the border-to-Fada and Fada-to-Ouagadougou sections.

The latest Niger-specific AfDB report reached a very different conclusion. It rated implementation unsatisfactory and said the contractor on the approximately 99-kilometre 330 kV line from Gourou Banda to the Niger–Burkina Faso border had been demobilised for more than two years. Without a restart agreement, the report warned that this segment might not be completed.[12] Other World Bank-financed Niger works had restarted in September 2024 and were reported at about 40% in June 2025, so even the country label conceals different contracts and trajectories.[10]

Official percentages are not methodologically stable. WAPP said overall execution had reached 65% by the end of 2024. A later official presentation reported 56% physical completion at the end of 2025.[13][14] That does not necessarily mean construction went backwards; the denominator, contract set or measurement method may have changed. It does mean an investor, government or journalist should not treat a single percentage as a complete status description.

The operational constraint is even sharper. AfDB reporting in 2025 said delays to a Nigerian Northern Corridor project meant initial North Core supply would have to use the existing Kainji–Birnin Kebbi infrastructure, limiting transit to 100 MW until additional works were available.[15] That practical limit is far below the new line's headline technical handling capacity.

The StoneComms conclusion is deliberately narrow: as of 14 September 2026, Burkina Faso's AfDB-financed substation and dispatch package had reached testing, but authoritative sources did not establish full end-to-end energisation or sustained commercial trade. The corridor's status was set by the missing span, not by the most advanced work package.

THE MARKET CAN EXIST AND STILL BE THIN

Southern Africa shows the next layer of constraints

The Southern African Power Pool offers the continent's clearest live market evidence. It operates day-ahead, intraday and forward products alongside bilateral contracts. Competitive activity is growing: SAPP reported 1,311 GWh of competitive-market volume in the 2025/26 financial year, up 68.7% from the previous year.[16]

But the June 2026 report shows why a functioning exchange is not the same as a deep, unconstrained market. The day-ahead market received 327 GWh of buy bids and 1,002 GWh of sell offers. Only 137.4 GWh matched, and 97.4 GWh was ultimately traded. Across all competitive products, 47 GWh of matched energy was blocked by transmission constraints, particularly on the Zimbabwe–Zambia corridor.[2]

The platform's role also remains smaller than the bilateral market. In May 2026, competitive products accounted for 18% of all SAPP trade; bilateral contracts supplied 82%.[2] The balancing market illustrates the difference between having a product and using it: SAPP reported no activated orders since that market opened in April 2022, despite large quantities of automatically transferred bids.

None of this diminishes SAPP's achievement. It clarifies the next investment agenda. More participants, stronger transmission corridors, transparent wheeling charges, coordinated planning and creditworthy counterparties are not supporting details. They are the mechanisms through which installed regional capacity becomes traded electricity.

The World Bank's RETRADE programme recognises this. Its Southern Africa operation combines institutional support with preparation of interconnectors and a regional transmission financing facility initially targeting US$1.3 billion.[17] The architecture joins capital with regulation, market participation and project preparation. That is closer to the actual shape of the problem than treating every constraint as a shortage of construction finance.

BILATERAL TRADE IS PROGRESS, NOT A FINISHED MARKET

Eastern Africa shows why the platform measure matters

Eastern Africa's cross-border electricity trade rose from 280 GWh in 2010 to 3,217 GWh in 2023, according to the African Development Bank. Transmission networks expanded from 303 kilometres in 2010 to 2,753 kilometres in 2024.[4] Those are material gains.

Yet the Eastern Africa Power Pool's central market platform recorded zero GWh against a 200 GWh target in its May 2026 implementation report; participating countries were recorded at zero against a target of seven.[3] Trade continued under bilateral agreements while the Day-Ahead Market was scheduled for 2026. The high-level market design existed, but binding commercial rules, regional grid reliability, centralised operation, interface systems and national-regional planning still needed work.[18]

This is not a contradiction. It is an analytical distinction. Bilateral trade proves that neighbouring systems can exchange electricity under specific contracts. A central platform requires common rules, standard products, transparent access, coordinated dispatch, dependable data, settlement arrangements and enough participants to generate useful price formation.

The same distinction applies continent-wide. The African Single Electricity Market was politically launched in 2021, but its full operating horizon is 2040. The African Union's 2026 work programme still centres on regulatory harmonisation, utility performance, infrastructure, and coupling the regional pools.[5][19] AfSEM should therefore be described as an implementation programme toward a continental market, not as a live continent-wide exchange.

PAYMENT SECURITY IS GRID INFRASTRUCTURE

A transaction fails if the buyer cannot settle

Regional trade is exposed to the balance sheets of national utilities. A 2025 World Bank study covering 67 utilities in 47 sub-Saharan African countries found that more than two-thirds of vertically integrated and distribution utilities could not cover operating costs and debt service from revenue. Collection leakage exceeded 10% for 14 of the 26 entities with collection data and exceeded 40% for eight.[20]

West African utilities face high supply costs, network losses, collection problems and accumulated arrears. The first phase of the World Bank's US$1.6 billion West Africa Regional Electricity Market Program consequently includes market and regulatory institutions rather than financing only transmission. Programme documents address cross-border payment arrears, utility-improvement plans and risk mitigation.[21]

Foreign exchange adds another dependency. WAPP's August 2026 update said agreement had been reached with a market-clearing bank, while operational work continued on cross-border foreign-currency settlement.[7] A seller paid late, in the wrong currency or without enforceable security will ration exposure, whatever the physical capacity of the line.

This is why liquidity facilities, letters of credit, escrow arrangements, market surveillance, enforceable contracts and credible dispute resolution should be evaluated as part of the corridor. They are not financial accessories placed around an engineering asset. They determine whether scheduled power becomes a settled transaction and whether suppliers return to the market tomorrow.

The political layer also matters. World Bank programme documents noted that Nigeria–Niger electricity supply was interrupted for eight months during ECOWAS sanctions, prompting some importers to reconsider dependence.[22] Diversified routes and reciprocal commercial benefit can make a system more resilient, but only if the governance framework can withstand political stress.

WHOLESALE SAVINGS DO NOT AUTOMATICALLY REACH THE CUSTOMER

National and distribution networks complete the circuit

Regional imports can reduce expensive thermal generation. In Guinea-Bissau, the World Bank reported that imported hydroelectricity helped replace rented heavy-fuel-oil generation and cut generation costs from about US$0.25 to US$0.11 per kWh. The national utility moved from a roughly US$1 million monthly deficit to a positive operating balance. The Gambia's utility returned to profitability with reported cost savings of about 42%.[1]

Those outcomes are important. They also depend on what happens after the border. Transmission and distribution losses in sub-Saharan Africa were equivalent to 26% of output in 2024, according to World Bank data.[23] Weak feeders, overloaded transformers, inaccurate meters and poor collection can absorb the value created upstream. A lower import price may improve a utility's variable cost without producing a lower tariff or more reliable service.

The experience of rural electrification along the Côte d'Ivoire–Liberia–Sierra Leone–Guinea corridor makes the point tangible. In Sierra Leone, an AfDB report said all target corridor localities had been described as electrified, but power reached only 18.75% of the target because many locations had not yet been energised. Thirty-one villages were energised and 26 were pending. Traded electricity cost US¢11.35/kWh, below the project target, yet the average retail tariff remained US¢22/kWh because higher-cost generation stayed in the supply mix.[24]

In Liberia, a 2025 report described access constraints created by poor roads, difficult terrain, a three-kilometre project boundary around the high-voltage line, and households moved beyond feasible distribution reach by road construction.[25] The transmission corridor existed. The final kilometres did not consistently convert proximity into service.

Projects designed around the full chain look different. The Uganda–South Sudan interconnection combines a high-voltage line with 33 kV distribution, low-voltage reticulation, last-mile connections, a cost-of-service study, utility capacity building and livelihood restoration.[26] The scope acknowledges that wholesale transfer capacity and household access are separate investments that must be planned together.

THE RIGHT OF WAY IS PART OF THE BALANCE SHEET

Safeguards are a delivery condition, not a footnote

Transmission corridors occupy land, cut across livelihoods and create construction risk. Those impacts carry ethical, political, schedule and financing consequences.

Environmental and social assessment for the Ghana–Côte d'Ivoire interconnector identified 709 project-affected people on the Côte d'Ivoire alignment, alongside farms, plantations and a palm-processing facility. In Ghana, the proposed right-of-way included active and abandoned informal gold-mining pits near seven communities. The project was rated high environmental and social risk.[27]

Domestic financing constraints later threatened compensation and resettlement readiness, leading to requests for additional or exceptional financing.[28] Compensation is therefore not a peripheral social line item. If it is unfunded or delayed, it becomes a critical-path capital requirement.

The risks can be acute. A World Bank supervision mission for the Mozambique–Malawi interconnector recorded two worker fatalities linked to subcontractor safety failures, alongside delays in replacement housing, livelihood restoration and community assets.[29] A project can be technically important and still fail its host communities or workforce. Treating safeguards as a late compliance exercise raises human harm and delivery risk together.

Communities hosting towers and rights of way should not be assumed to benefit from access. A credible local-benefit plan identifies the feeders, transformers, meters, service standard, tariff mechanism and delivery timetable. It also funds compensation, grievance resolution, livelihood restoration and long-term maintenance.

THE CORRIDOR READINESS LEDGER

Judge the system by the least-ready layer

StoneComms proposes a seven-part ledger for governments, development financiers, utilities and investors. It is a decision instrument, not a universal ranking. Each layer should be scored with dated evidence, a named accountable institution and a clear threshold for commercial operation.

1. Physical completion and redundancy. Are every line lot, substation, protection system, fibre link and connection bay finished and tested? What transfer capacity is actually available under the current network configuration, rather than the design maximum? Is there an alternative route during maintenance or political interruption?

2. Synchronisation and operations. Can the connected systems maintain frequency and voltage through disturbances? Are operating procedures, reserves, maintenance windows, telemetry, SCADA and real-time data in place? Has the corridor completed sustained operation, not only a trial?

3. Market rules and access. Are wheeling charges, losses, congestion, nominations, imbalances and curtailment handled under transparent rules? Can eligible buyers and sellers access the line without discretionary barriers? Is the regulator's authority recognised across jurisdictions?

4. Settlement and payment security. Who invoices, in which currency and on what timetable? What protects sellers against arrears, convertibility risk and default? Are contracts enforceable, disputes resolvable and credit exposures visible?

5. Tradable supply and demand. Is surplus generation available when the buyer needs it? Are there enough participants, bids and offers to create liquidity? How much matched power is blocked by constraints? Are bilateral and competitive trades reported separately?

6. National and local delivery. Can national transmission receive the import without creating a new bottleneck? Which feeders, transformers, meters and customer connections convert wholesale energy into service? Are losses, collections and tariff pass-through addressed?

7. Safeguards, maintenance and governance. Is compensation funded? Are grievances, safety, gender-based-violence risks and livelihood restoration on the critical path? Who pays for maintenance and replacement? Which institution owns each failure mode?

A corridor should not be declared ready because the average score is high. Power cannot route around a missing contract, an unpaid invoice or an unbuilt border span simply because other components are exemplary. Decision-makers should publish the lowest score, the evidence date and the remedial owner.

WHAT CAPITAL PROVIDERS SHOULD REQUIRE

Finance the chain, then measure the transaction

First, financing packages should join the physical and institutional scopes. Lines and substations need parallel budgets for market systems, regulatory implementation, utility reforms, distribution reinforcement, connections, compensation and maintenance. Separating them into projects with different timetables creates stranded-capacity risk.

Second, disbursement and completion reporting should distinguish work packages. The North Core example shows why a percentage for a local substation package cannot stand in for a national segment or a regional corridor. Dashboards should report each contract, interface and energisation milestone.

Third, performance metrics should follow electricity through the chain. A useful minimum set includes available transfer capacity, scheduled and delivered MWh, constrained-off MWh, settlement timeliness, arrears, loss rates, outage minutes, connections energised, service hours, retail-cost pass-through and safeguard commitments closed.

Fourth, the base case should stress payment and politics, not only hydrology and demand. Scenarios should include currency shortage, buyer default, sanctions, a major corridor outage, maintenance delay and prolonged non-payment. Risk mitigation should specify who carries each exposure.

Fifth, local delivery should be named before financial close. If a project claims access benefits, its investment documents should identify the distribution equipment, connection numbers, responsible utility, operating budget, tariff or subsidy arrangement, and communities expected to receive service.

Finally, public communication should separate forecasts from observed results. A commissioning date is not a commissioning record. A target for energy traded is not energy delivered. A modelled cost reduction is not a tariff cut. Precision strengthens the case for regional integration because it directs attention to the investment still required.

RESEARCH AGENDA

The missing data should become a procurement brief

The next phase of public research should build a corridor-level dataset across Africa's five power pools. For every active and planned interconnector, it should reconcile contract packages, physical status, operational capacity, scheduled and delivered energy, congestion, settlement performance, utility arrears, outage records, distribution scope and safeguard commitments.

Three commissioned studies would add particular value.

The first is a payment-security comparison covering liquidity facilities, guarantees, escrow, clearing banks and currency arrangements across WAPP, SAPP and EAPP. It should test which instruments have actually shortened settlement times and expanded counterparties.

The second is a last-mile benefit audit of communities within transmission corridors. It should compare households and firms crossed by rights of way with those energised, the quality and price of service they receive, and the status of compensation and livelihoods.

The third is a congestion-to-capital map linking constrained-off energy to specific network reinforcements. SAPP's market data already shows the value of this approach: offers and matched trades reveal where scarce transfer capacity is suppressing useful exchange.

This work would help governments and financiers decide whether the next marginal dollar belongs in a new line, an existing bottleneck, a market platform, a settlement facility, a distribution programme or utility reform.

CONCLUSION

Africa's regional power ambition is moving from diagram to system. The lines matter because geography distributes hydropower, solar, wind, gas, demand and reserve needs unevenly. Trade can lower costs, improve reliability, reduce emergency thermal generation and make larger renewable portfolios viable.

But the economic asset is not the interconnector alone. It is the repeatable transaction that crosses it, settles on time, survives a constraint, reaches a customer and funds the system's next day of operation.

The missing span may be a 99-kilometre line. It may also be a tariff method, a currency account, a solvent buyer, a transformer, a compensation payment or an operator trained to manage an imbalance. The practical task is to find that span before celebrating the parts already complete.

Regional integration should continue. Its next discipline is to measure readiness as a chain—and invest at the weakest link.