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The Eastern Africa Power Pool (EAPP) encompasses thirteen member countries with substantial but largely untapped Variable Renewable Energy (VRE) potential. Electricity trade currently relies on long-term bilateral power purchase agreements between state utilities. These arrangements are not suited to the short-term variability of wind and solar generation and are unable to provide the pricing signals needed to attract private investment. With the EAPP scheduled to launch a day-ahead wholesale market in 2026, this study provides timely quantitative and qualitative evidence to inform its design. Three research questions were addressed: how electricity is traded globally and in Eastern Africa; how a wholesale market would be affected by increasing VRE penetration; and how accurately the simulation models EAPP short-term trading dynamics. A sequential explanatory mixed-methods design was used. Agent-based simulations using the AMIRIS model modelled five EAPP countries, Kenya, Uganda, Tanzania, Ethiopia, and Rwanda, for 2025. They compared the base scenario (5.5% wind and solar share of installed capacity) against a high-VRE scenario (24.2%). Three sensitivity scenarios examined geothermal dispatch priority, intermediate VRE penetration, and the capacity threshold at which mean market prices turn negative. Eleven key informants from regulators, utilities, generators, and the EAPP Secretariat validated model assumptions and findings through semi-structured interviews. Market structures across the five countries range from vertically integrated monopolies to partially unbundled frameworks. The simulation found that a day-ahead market would reduce average dispatch costs. Under the base scenario, the average clearing price was 67.5 EUR/MWh with VRE supplying 85% of energy. In the high-VRE scenario, the mean price collapsed to −295.57 EUR/MWh, with VRE supplying 99% of energy, and prices negative in 77% of hours. The optimal-VRE scenario identified 18.6% of the planned high-VRE increment as the ceiling beyond which mean annual prices turn negative. Quantitative validation against Kenyan 2023 grid statistics achieved a 0.58% energy deviation. Qualitative review identified the infinite transmission assumption as the principal model limitation.
The study found that short-term trading would lower prices and expand VRE dispatch, but rapid unmanaged expansion produces sustained negative pricing and suppresses investment signals. Price floors, contracts for difference, geothermal dispatch guarantees, and staged capacity planning are necessary to sustain investment whilst delivering consumer welfare gains. This study contributes the first agent-based market simulation for the EAPP and a replicable methodology for identifying VRE absorption capacity in emerging wholesale markets.