Twelve African utilities owe independent power producers (IPPs) $8.64 billion. In 2025 they paid back $755 million. Then the stock barely moved, because the regulator-set tariff does not cover the cost of supply. Every kilowatt-hour sold widens the hole.

Executive Summary

$8.64 billion in disclosed IPP arrears across twelve African utility offtakers in Q1 2026. Five Tier 3 utilities (NBET, ENEO, Senelec, ZETDC, EEU/EEP) hold $5.78 billion, 67% of total. They publish too little for quantitative risk analysis.
Supply cost recovery isolates the constraint. KPLC (Kenya) is the cleanest case. Its tariff-gap ratio of 0.85 means the regulator-approved tariff already underprices supply by 15%. Effective collection at 0.71 adds 14 more percentage points. Pricing dominates; collection accelerates.
Foreign exchange cuts both ways. Ghana’s cedi rallied from ~14.6 to 10.79 per dollar through 2025, narrowing ECG/VRA’s tariff gap. Zambia’s kwacha appreciation pushed ZESCO’s ratio to 1.04, the only utility where approved tariff exceeds cost. Both moves are reversible.
2025 paydowns split into three categories. Direct IPP settlement: $755 million. Adjacent power-sector liability events: $1,077 million. Balance-sheet liquidity: $215 million. Restructuring transfers liability between balance sheets without closing the cost-recovery gap.
Disclosure depth is the screen. NBET, ENEO, ZETDC, and EEU/EEP together hold $5.0 billion in disclosed arrears but publish too little for supply cost recovery or severity analysis. The opacity maps onto jurisdictions where the tariff gap is largest and the political cost of quantifying it is highest.

How to Read This

African independent power producer credit risk is typically framed as an arrears-severity question: how large is the stock, and can it be paid down? That framing misses the structural issue. The stock is large because the regulator has set a tariff that does not cover the cost of supply. Every kilowatt-hour delivered adds to the exposure. Restructuring instruments—bonds, securitisations, waterfall mechanisms—transfer existing arrears between balance sheets without closing the cost-recovery gap that produces the liability. The exposure reaccumulates.

What that means depends on where you sit.

For development finance institutions and blended finance

Additionality re-prices here. The sovereign-guaranteed power purchase agreement (PPA) is no longer underwritable at scale. Credit enhancement migrates onto partial-risk guarantees (PRGs), liquidity facilities, and PRG-substitution structures. The portfolio question: does your concessional capital follow the cost-recovery gap into PRGs, transmission, mini-grid aggregation, and captive-generation enabling frameworks, or stay parked in utility-scale renewables that infrastructure equity will fund without you?

For infrastructure equity and private credit

Where a state utility has crossed the cost-recovery cliff, the marginal megawatt finds a different counterparty: hyperscalers, mineral processors, Carbon Border Adjustment Mechanism (CBAM)-exposed exporters, gas-to-industrial buyers, and large industrial corporates. Underwriting the next decade of African clean energy means building corporate-offtaker credit muscle at scale and aggregation discipline for behind-the-meter commercial and industrial (C&I) projects. Mid-market lenders already do this for small and medium enterprises in Organisation for Economic Co-operation and Development (OECD) markets. The capability does not yet exist in standardised form for African industrial customers.

For climate and transition specialists

Coal retirement, just-transition obligations, and renewable deployment all hinge on whether the offtaker can pay for the new dispatch. Where utility offtake is structurally non-cost-recovering, the transition stalls, even when concessional capital is available and policy alignment exists. The conditionality that unlocks deals is offtaker substitution, not climate ambition. Funds bound by categorical asset-class rules miss the deals that solve the bankability problem. Funds that build offtaker substitution into their underwriting close them.

What We Can Measure, and Where the Gap Is

The analysis covers twelve utility offtakers across eleven African jurisdictions. Disclosed IPP arrears total $8.64 billion. Disclosure is sharply uneven by tier.

Tier 1 Utilities: Kenya Power and Lighting Company (KPLC) and the Electricity Company of Ghana/Volta River Authority (ECG/VRA), publish enough for full supply cost recovery decomposition.
Tier 2 Utilities: ZESCO (Zambia), Uganda Electricity Transmission Company Limited (UETCL), Electricidade de Moçambique (EDM), Compagnie Ivoirienne d’Électricité (CIE), and Société Tunisienne de l’Électricité et du Gaz (STEG), publish partial data sufficient for either severity or cost-recovery analysis.
Tier 3 Utilities: Nigerian Bulk Electricity Trading (NBET), ENEO (Cameroon), Senelec (Senegal), Zimbabwe Electricity Transmission and Distribution Company (ZETDC), and Ethiopian Electric Utility/Ethiopian Electric Power (EEU/EEP), disclose arrears figures but no revenue, tariff, or cost-of-supply data at primary-source quality. The five Tier 3 utilities together hold $5.78 billion, 67% of the total.

A note on method. Every cell is anchored to a primary source (audited financials, regulator order, sovereign bond prospectus, ministry release) within a 12-month recency window, extended to 24 months for multi-year tariff orders. Where disclosure is broader than IPP-only, scope substitution is permitted with explicit flagging (true for the seven Tier 2 and Tier 3 utilities that do not disaggregate).

Ring-fenced exposures such as Eskom under the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP), the Egyptian Electricity Transmission Company (EETC) under sovereign escrow plus political risk insurance (PRI), and the Office National de l’Électricité et de l’Eau Potable (ONEE) under dedicated escrow, sit on a separate Ring-Fenced Watchlist and only enter the active universe on material ring-fence strain.

Limitations: scope-substituted figures overstate IPP-only exposure; foreign-exchange-driven ratios reverse on currency reversal; trended cost-of-supply carries methodological uncertainty.

Figure 1: Disclosed IPP arrears by utility and tier, Q1 2026.

Cost Recovery: Where the Data Is

Two utilities publish enough to test the cost-reflective tariff thesis directly. Both fail. KPLC fails by 29 percentage points end-to-end. ECG/VRA’s allowed tariff sits 2% below cost; effective collection data is too thin for full primary-source analysis. ZESCO is the only utility where the approved tariff exceeds cost, and the configuration is foreign-exchange-driven and reversible.

KPLC (Kenya): the cleanest decomposition in the sample

According to KPLC’s FY2024/25 annual report, arrears stand at $128 million (KES 16.5 billion at year-end FX of 129 KES/USD), against annual revenue of $1.7 billion (KES 219.3 billion). The EPRA-approved tariff is 17.8 USc/kWh (~KES 22.96/kWh), cost of supply is 21.0 USc/kWh, and effective collected is 14.9 USc/kWh. Tariff-gap ratio 0.85, cost-recovery ratio 0.71. The Kenyan Treasury holds majority stake; the World Bank Power Sector Recovery Programme, the International Monetary Fund (IMF) programme, and the African Development Bank (AfDB) Mission 300 are all engaged. Token-prepaid metering complaints recur in EPRA public consultations and the fuel cost charge remains a political flashpoint, yet KPLC is widely regarded as the most transparent utility in the sample. Disclosure quality is itself the leading indicator.

The supply cost recovery decomposition isolates the binding constraint. The 15-percentage-point tariff gap means the regulator is already below cost before a single invoice is delayed. The 14-percentage-point collection drag adds on top. Pricing is the larger contributor. In flow terms, KPLC delivers $1.7 billion (KES 219.3 billion) of revenue annually at a 0.71 cost-recovery ratio. That arithmetic implies approximately $0.49 billion (KES 63.2 billion) of new arrears creation per year if structural conditions do not change, for a single utility. The aggregate reaccumulation visible in the 2025 paydown arithmetic is exactly what unit-level supply cost recovery analysis predicts.

ECG/VRA (Ghana): narrowest gap in the sample, FX-anchored

Per the Public Utilities Regulatory Commission (PURC) quarterly tariff orders and Ghana’s Ministry of Finance January 2026 release titled “Mahama Administration Pays US$1.470 Billion to Clear Energy Sector Debt,” ECG/VRA arrears stand at $1,100 million (GHS 11.87 billion). The allowed tariff of 16.2 USc/kWh sits just below cost of supply at 16.5 USc/kWh, producing a tariff-gap ratio of 0.98, the narrowest in the sample.

The 54% settlement rate suppresses full supply cost recovery analysis at Tier 1 quality. The cedi’s rally from ~14.6 to 10.79 per dollar through 2025 drove the tariff gap from the ~0.73 range toward near-unity by Q1 2026. Currency appreciation, not structural reform, moved the ratio. “Dumsor” returned in 2023-2024 and was a major issue in the December 2024 election; the Mahama administration’s $1.47 billion clearance was politically driven.

ZESCO (Zambia): outlier above unity, FX-driven

According to the ZESCO Integrated Report 2024 (December 2025) and the Energy Regulation Board’s November 2025 tariff order, arrears stand at $337 million (ZMW 6.57 billion) against $1.58 billion (ZMW 30.8 billion) annual revenue. The allowed tariff of 17.7 USc/kWh exceeds cost of supply at 17.0 USc/kWh, producing a tariff-gap ratio of 1.04, the only figure above unity in the sample. Zambia’s kwacha appreciation through 2024-25 explains it: dollar-denominated supply costs fell in kwacha terms faster than the tariff adjusted. This is temporary; a reversal restores the gap. Zambia exited Common Framework restructuring in June 2024; the International Monetary Fund Extended Credit Facility (ECF) is in implementation; the 2023-24 hydro drought caused 8-12 hour daily blackouts before Kafue Gorge Lower commissioning helped 2025 recovery.

Figure 2: Supply cost recovery decomposition for measurable utilities.

Foreign Exchange Is the Accelerant

The tariff gap is not fixed. Dollar-denominated power purchase agreements translate into local-currency tariff requirements that track the exchange rate. When the local currency weakens, the per-kWh cost of contracted supply rises in local terms, and the gap widens; when it strengthens, the gap narrows or, as in Zambia’s case, temporarily closes.

This cuts both ways. Currency stabilisation programmes driven by International Monetary Fund and World Bank conditionality directly improve offtaker financials—as Ghana’s 2025 experience shows—without any change in the underlying tariff order. But the improvement is reversible. A tariff that does not cover costs at a stronger exchange rate leaves the structural gap intact.

Currency stabilisation and disclosure improvement travel together—both are outputs of the same programme conditions. IMF Article IV consultations, World Bank power-sector reviews, and development finance institution programme requirements simultaneously demand exchange-rate adjustment and utility-sector disclosure. The utilities with the strongest disclosure scores, KPLC, ECG/VRA, ZESCO, operate in sovereigns with the deepest multilateral programme relationships. The empty cells in the tracker map onto jurisdictions where those relationships are absent or fractured. The opacity is itself a signal.

2025: Direct Settlement and Adjacent Events

The headline numbers from 2025 look better than the reality. Two distinct categories of power-sector liability reduction occurred, and conflating them misrepresents both the scale and the nature of what was settled.

Per the Ghana Ministry of Finance press release of January 2026, Ghana paid $393 million (GHS 4.24 billion) in IPP arrears during full-year 2025, the IPP-specific component of a broader $1.47 billion (GHS 15.86 billion) energy-sector settlement. Per the Federal Ministry of Information and National Orientation (FMINO) press release of December 19, 2025 and the Nairametrics confirmation of January 28, 2026, Nigeria issued the inaugural ₦501 billion ($362 million) tranche of the ₦4 trillion Power Producers Settlement and Debt Redemption Programme (PPSDRP) in December 2025; subscription closed in January 2026. Both instruments transfer credit exposure from the utility to a sovereign or sovereign-adjacent balance sheet. Direct IPP-arrears settlement: $755 million.

From the same Ghana Ministry of Finance announcement, $597 million (GHS 6.44 billion) restored the World Bank partial risk guarantee and $480 million (GHS 5.18 billion) settled Sankofa gas-supplier obligations to ENI and Vitol. Neither retires IPP arrears, though both restore credit-enhancement infrastructure. Adjacent power-sector liability events: $1,077 million.

Senelec’s October 2025 Banque Ouest Africaine de Développement (BOAD) Titrisation transaction raised XOF 120 billion ($215 million) through a sustainability-linked securitisation, per the GuarantCo press release. The structure securitises inbound receivables; proceeds are earmarked for renewables capex and sustainability key performance indicators. It is balance-sheet liquidity, not arrears settlement: $215 million.

The combined sector-wide figure is $2.05 billion. The direct IPP component is $755 million. None of the three closes the cost-recovery gap that produces the liability in the first place.

Figure 3: 2025 power-sector liability events, decomposed.

Where the Marginal Megawatt Migrates

The cost-recovery cliff does not stop the load. African electricity demand keeps growing, driven by industrial electrification, urbanisation, artificial intelligence and data-centre buildout, mineral processing, and CBAM-exposed exports. What stops is the utility’s ability to underwrite the marginal megawatt. So that megawatt finds a different counterparty: hyperscalers, mineral processors, CBAM exporters, gas-to-industrial buyers, and large industrial corporates. Where the legal scaffolding now permits private wheeling and corporate power purchase agreements at scale: South Africa’s Electricity Regulation Amendment Act 38 of 2024, Nigeria’s Electricity Act 2023, Kenya’s wheeling code revisions, Ghana’s open-access framework, commercial and industrial solar-plus-storage is migrating from balance-sheet financing into bankable project finance.

What We’re Watching

Three signals will move the readings before the second quarter of 2026. Ghana’s financial year 2025 audit (expected Q3 2026) closes ECG/VRA’s effective-collected gap. An audited collection rate near the 16.2 USc allowed tariff would push the tariff-gap ratio toward unity on paper, without any underlying structural change. The next Nigerian Electricity Regulatory Commission Multi-Year Tariff Order supplementary order (rumoured Q2 2026) determines whether Band A pricing extends to Bands B and C; without it, NBET stays analytically opaque. Tunisia’s IMF programme remains stalled, and STEG’s Tier 2 status holds only as long as supplier-payables disclosure continues.

Bottom Line

African IPP arrears are a fiscal subsidy carried on utility balance sheets. The regulator sets a tariff below cost, currency movements widen or narrow the gap, and sovereigns periodically pay it down through instruments that transfer liability between balance sheets without closing the gap. The cycle will not close until the tariff becomes cost-reflective.

In the meantime, capital migrates. The next decade of bankable African clean energy generation is being underwritten not against state utility offtake but against a new class of investment-grade, hard-currency industrial counterparty.