Six listed African power generation companies (gencos), covering 8,543 MW of installed capacity across five countries, reported Net Plant Load Factor (PLF), defined as energy sold over maximum possible output, between 33.7% and 80.3% at their latest fiscal year (FY). The cohort mean is 60.4%. Only Morocco’s TAQA Morocco (80.3%) clears the 80% investment-grade threshold. Nigeria-based Geregu Power sits just below at 77.2%. The other four (Mozambique’s HCB, Nigeria’s Transcorp Power, Kenya’s KenGen, and Uganda’s UEGCL) run between 33.7% and 67.8%.

Split PLF into its two drivers, and the spread tells a different story. PLF is Availability multiplied by Dispatch: the share of hours the plant was ready to run, times the share of that available capacity the grid bought. Five of the six gencos hold availability above 90%; utilisation collapses on dispatch, falling to 56% for Nigeria-based Transcorp Power, 54% for Kenya’s KenGen, and 34% for Uganda’s UEGCL. The plants are ready. The buyer is not.

For capital allocators, this reframes the underwriting question. Capacity expansion does not fix what the grid will not take. The screen is the dispatch counterparty (whether it can pay, and whether it has the transmission to evacuate the energy), not the asset. It is the same dynamic as our Independent Power Producer (IPP) Arrears reading, seen from the Genco’s side of the meter: where the utility cannot pay, it does not dispatch.

Executive Summary

• 47-point spread, one investment-grade Genco. Across FY2024–FY2025 latest reports, Net PLF ranges from 33.7% (UEGCL) to 80.3% (TAQA Morocco). Only one Genco breaches the 80% utilisation threshold; one more (Geregu, 77.2%) sits within striking distance. The other four sell between 34% and 68% of their installed potential; UEGCL alone runs below half. A 47-point spread is wider than asset-quality differences can plausibly explain.
• Five of six are dispatch-bound: the plant is ready, the buyer is not. Availability sits above 90% for UEGCL (97.7%), KenGen (96.2%), TAQA Morocco (93.0%), Transcorp (92.3%), and HCB (91.1%). Plant Load Factor collapses because dispatch (energy sold per MW-hour the plant was available) falls to 34.5% (UEGCL), 53.7% (KenGen), 56.2% (Transcorp), 74.4% (HCB), 86.3% (TAQA). The cohort is constrained by what the grid takes, not by what the plant offers.
• Geregu is the only availability-bound case: the grid will take everything it can produce. Availability at 78.0% (the cohort low), but dispatch when available at 98.9% (the cohort high). Every megawatt-hour Geregu can produce is sold. The headroom sits on the asset side, not the offtake side. That single distinction separates two capital-expenditure cases that look identical from the outside: one where new spend buys uptime and gets paid, and five where new spend buys uptime that no one will take.
• Monetisation tracks utilisation, not capacity. Revenue per MW follows PLF rank one-for-one across the cohort. A simple regression of revenue per MW on PLF across the six gencos fits at Rev/MW ≈ $3.3k per percentage point of PLF, plus a $47k floor (R² = 0.71). Gas plants in particular price energy delivered, not capacity contracted: Transcorp and Geregu, despite similar Power Purchase Agreement (PPA) structures, post Earnings Before Interest, Tax, Depreciation and Amortisation (EBITDA) margins of 32.8% and 31.8% respectively, both moving directly with dispatch. Capacity-payment clauses do not insulate underutilised assets in this cohort.
• The new MW is being built for someone other than the utility. 2025 saw an estimated 240 MW of power contracted directly by data-centre operators (Equinix, Raxio, Cassava) across Sub-Saharan Africa, plus an estimated 1.3 GW of captive solar built to bypass the utility altogether. Mineral processors and exporters exposed to Europe’s Carbon Border Adjustment Mechanism (CBAM) signed Power Purchase Agreements (PPAs) at $0.07–$0.14/kWh. New capital is no longer being deployed against state-utility dispatch, and the listed Genco cohort is the legacy stack the new money is moving past.

The Cohort, Ranked

The six gencos are the listed African generators with sufficient annual-report disclosure to anchor every operational cell to a primary source within a 12-month recency window. Four (Geregu, Transcorp, KenGen, UEGCL) file on June or January fiscal years and have published FY2025. Two (TAQA Morocco, HCB Mozambique) file on December fiscal years and the most recent audited disclosure is FY2024, with FY2025 expected in Q3 2026. The reading is therefore a mixed-year cohort: the latest published fiscal year per Genco.

The PLF in this cohort is Net basis. The numerator is energy sold, not energy generated, which means the headline absorbs two losses upstream: capacity unavailable, and capacity available but undispatched. Net is the investor’s convention; it prices the revenue line, not theoretical output.

Figure 1: Net PLF, latest reported FY. The 47-point spread inside a single asset class is wider than operating variance can carry.

Read across the cohort. TAQA Morocco is the only Genco any investor would underwrite at full utilisation today. Geregu is one operational fix away from joining it: recovering availability. The bottom four are not asset failures. They are demand-constrained: building more capacity at any of them would not add revenue.

Where the Constraint Sits

A 60% mean PLF first looks like an operations problem: maintenance, fuel, water levels, transmission losses. If that were the diagnosis, the lever would be capital spending at the plant. Splitting PLF into Availability and Dispatch tests that hypothesis directly.

Where the shortfall lands, on the asset side or on the buyer side, tells the investor which lever moves revenue.

Figure 2: Availability versus dispatch by Genco. The vertical gap between the bars is where the value leaks.

Five of six gencos sustain availability above 90%, a level that matches global operating norms, not just regional ones. Dispatch is where the collapse happens. UEGCL stands ready at 97.7% but sells at 34.5% of available capacity; KenGen at 96.2% sells at 53.7%; Transcorp at 92.3% sells at 56.2%. These are not asset deficiencies. They are offtake ceilings the grid imposes: utility receivables that cannot absorb full dispatch, transmission constraints that cannot evacuate full output, or both.

The implication for capital allocation is direct. Spending capital to improve plant operations on a unit that is already 96% available adds zero megawatt-hours sold. The question shifts off the asset and onto the buyer: is there a credible path to corporate PPAs, industrial captive offtake, or regional export inside the contract horizon? Where there isn’t, new capacity simply funds idle iron.

Geregu: the reverse case

Nigeria-based gas Genco Geregu Power inverts the cohort pattern. Its availability sits at 78.0%, the lowest of the six, but when the plant is running it dispatches at 98.9%, the highest in the cohort. Geregu’s own FY2024 Annual Report and Q1 2025 unaudited update show the plant running close to its 435 MW nameplate during operating periods; the constraint is asset readiness, not buyer behaviour. This is the operational improvement case the rest of the cohort does not have. For Geregu, every percentage point of availability translates one-for-one into revenue.

The Rev/MW evidence confirms the asymmetry. Geregu earns $295.5k per MW, within $1k of TAQA Morocco’s $296.8k despite TAQA running at a higher PLF. Geregu’s revenue per available MW-hour is the cohort’s highest. For UEGCL, KenGen, and Transcorp, the same percentage point of availability translates into nothing unless the dispatch ratio moves with it.

Monetisation Tracks Utilisation

Capacity charges (the take-or-pay portion of a tariff that pays for installed MW regardless of energy delivered) are often assumed to insulate IPP cash flows from underutilisation. The cohort data says they do not. PLF rank tracks Rev/MW rank one-for-one across all six gencos; if capacity payments were doing the heavy lifting on revenue, that relationship would be roughly flat.

Figure 3: PLF versus Revenue per MW. The linear fit explains the cohort directly: the market pays for what the grid takes.

Plot Revenue per MW against PLF for the six gencos and the points sit close to a single straight line. Each additional percentage point of PLF adds roughly $3.3k of revenue per MW. The line bottoms out at a $47k floor: what the cohort earns per MW even when dispatch falls to zero. That floor is the residual capacity payment, the portion of revenue paid for being on the grid regardless of energy delivered. Everything above it is paid for energy actually sold.

The line fits each Genco closely. UEGCL at 34% PLF earns $112k per MW against the $160k the line would predict. TAQA at 80% earns $297k against $311k. The deviations are small. Capacity payments give the cohort a thin base; the rest of revenue moves with what the grid takes, and it does so the same way for every contract in the cohort, regardless of how each PPA is structured.

The contract mix, which shows how much of each Genco’s revenue is paid on installed capacity versus on energy delivered, differs across the cohort, but every contract ultimately prices energy. Geregu and Transcorp operate under Nigeria’s Bulk Electricity Trader (NBET) tariff with capacity-payment and energy-payment components; the energy component dominates revenue in practice. KenGen contracts with Kenya Power & Lighting Company under a regulated tariff that pays disposals. UEGCL contracts with the Uganda Electricity Transmission Company Limited (UETCL) on a similar dispatched-energy basis. TAQA Morocco’s Jorf Lasfar PPA with Morocco’s Office National de l’Electricite et de l’Eau Potable (ONEE) carries a stronger capacity component but still prices energy delivered. HCB sells primarily into Mozambique’s domestic grid and the South African Pool under hydro disposal terms. Across the cohort, every contract ultimately rewards energy delivered.

Where the Marginal MW Migrates

The capital that will build the next decade of African generation is increasingly being directed at counterparties other than the state utility. Three flows make this concrete. First, data-centre operators (Equinix, Raxio, Cassava) contracted an estimated 240 MW of new dedicated power offtake across Sub-Saharan Africa in 2025 (Africa Data Centre Association, January 2026).

Second, mineral processors in the Democratic Republic of the Congo (DRC) copperbelt and Zambia signed corporate Power Purchase Agreements (PPAs) priced against hard-currency export receivables. Third, captive solar (on-site generation that bypasses the utility entirely) reached an estimated 1.3 GW of installed capacity (International Finance Corporation Captive Solar Annex, FY2025), concentrated in South Africa but accelerating in Nigeria, Kenya, and Ghana.

Every megawatt in that count is a megawatt that did not enter the listed Genco stack. The logic is the same as the dispatch-bound finding inside the cohort: the counterparty pays. A hyperscaler signs a corporate PPA at $0.10–$0.14/kWh against contracted load. A mineral processor signs at $0.07–$0.09/kWh against export receivables. The state utility dispatches against unfunded subsidies. The marginal investor is not waiting for the utility offtake to resolve itself.

This converges with the IPP Arrears reading from the demand side. Twelve African utility offtakers carry $8.64 billion in disclosed IPP arrears at Q1 2026; five Tier 3 utilities account for $5.78 billion of that. The same fiscal constraint that prevents the utility from paying full freight also prevents it from dispatching at full availability. The two are the same problem seen from opposite sides of the meter. Six gencos running below 70% PLF and twelve utilities carrying $8.6 billion in arrears are the same equation, written twice.

What We’re Watching

Three things will move the cohort readings over the next twelve months. First, TAQA Morocco and HCB will publish FY2025 audited results in Q3 2026; that will tell us whether the top-to-bottom gap in the cohort is narrowing or widening once everyone is on the same fiscal year. Second, Geregu’s FY2025 availability figure: a step up from 78% would close the cohort’s only availability-bound case and reinforce dispatch as the binding constraint across all six. Third, Nigeria’s eligible-customer reforms (which let large industrial buyers contract gencos directly) and Kenya’s wheeling tariff (which lets generators move power across the grid for a fee) both open paths for dispatch-bound MW to find non-utility buyers without new build.

On the disclosure side, the cohort is sufficient for FY2024–2025 utilisation work but not yet for granular signal extraction. Forced and planned outage hours are not disclosed in any of the eight annual reports examined for this edition. Plant Availability is the substitute. We expect this disclosure gap to narrow over the next two editions as African regulator-mandated Key Performance Indicator (KPI) templates mature.

The Bottom Line

The 47-point PLF spread across six African listed gencos is not a story about which gencos are well run. The five that dispatch below 75% are not poorly operated; they are well-operated assets running into an offtake ceiling the grid imposes. The one Genco that dispatches at 99% has the cohort’s lowest availability, and that gap is the only one a balance-sheet capex line can credibly close.

For this edition, the utilisation reading sits opposite our IPP Arrears Tracker. The utility’s inability to pay shows up here as the Genco’s inability to dispatch. Underwriting a PLF lift without first underwriting who the Genco will sell to is underwriting the wrong variable. The next decade of returns on Africa’s listed Gencos will be set by their buyers, not by how much power they can theoretically produce.