Energy trade tempers Nile water conflict

The paper addresses how benefit-sharing beyond water volumes—specifically, cross-border electricity trade—can reduce conflict over the Nile’s water. Transboundary rivers sustain half the world’s population and face increasing stresses from growth and climate change. Traditional water-centric negotiations in the Nile Basin, including around the Grand Ethiopian Renaissance Dam (GERD), have stalled. While benefit-sharing has succeeded in some basins, it has not yielded large-scale, acceptable solutions in the Nile. The authors hypothesize that quantifying multisector (water-energy-food-environment) interdependencies at high spatiotemporal resolution can reveal actionable, system-scale cooperation options. They focus on whether structured energy trade among Ethiopia, Sudan and Egypt can temper water allocation conflicts by aligning GERD operations with downstream water reliability while delivering energy and climate co-benefits.

Benefit-sharing is advocated for international river cooperation, shifting focus from water volumes to shared benefits (electricity, agriculture, fisheries). Successful examples include projects in the Senegal, Columbia and Orange–Senqu basins; however, in the Nile Basin successes have been small-scale (for example, the Rusumo Falls 80 MW hydropower plant shared by Rwanda, Burundi and Tanzania) and larger initiatives have faltered, such as the 2005 Joint Multi-purpose Project among Ethiopia, Sudan and Egypt, hampered by water-politics. Previous GERD analyses and negotiations (for example, the 2019–2020 Washington draft proposal) have remained water-centric, emphasizing release rules and drought mitigation. Prior studies often assumed sufficient electricity demand and did not dynamically couple energy demand with GERD operations. This study fills that gap by jointly simulating river and power systems, integrating PPAs and dispatch with hydrology, to quantify basin-wide water-energy benefits.

The study builds a high-resolution, integrated river basin–energy system simulator for the Eastern African Power Pool (EAPP) region spanning 13 countries (eastern DRC partially). It represents major infrastructure: 51 dams (41 existing, 4 under construction, 6 planned); 89 run-of-river schemes; 474 transmission lines; 12 solar and 45 wind farms; 197 thermal plants; and 19 irrigation schemes, plus environmental flows. River basin model: Implemented in Pywr (Python Water Resources), a linear programming-based water allocation simulator with reservoir operations, abstractions (irrigation, municipal/industrial), and hydropower nodes, run at weekly time steps using naturalized inflows (1972–2002). The Eastern Nile model (Ethiopia, Sudan, Egypt) is combined with the broader EAPP water system; calibration/validation used observed flows and reservoir levels at key stations. Energy system model: A security-constrained DC optimal power flow with intertemporal constraints and cost minimization. It includes multiple generation technologies (variable renewables, hydropower with and without storage, geothermal, nuclear, thermal), 300 buses, and cross-border interconnections. Hourly dispatch is simulated for one representative day per week (24 hours) to capture variability; renewable profiles are derived from external datasets. Integration: The two models are soft-linked via Pynsim (multi-agent framework), iterating at each time step to (1) reconcile hydropower production/consumption and (2) adjust hydropower targets when demand curtailment occurs (trigger threshold: 15% of peak demand), thereby feeding back power system needs into reservoir releases and vice versa. Scenarios: Five scenarios are analyzed. Baseline applies the Washington draft proposal release rules and existing 100 MW Ethiopia–Sudan PPA, with no Ethiopia–Egypt trade. Four increasing-trade scenarios specify firm exports from Ethiopia to Sudan and Egypt in 100 MW increments: Low (200/100 MW), Medium-low (300/200 MW), Medium-high (400/300 MW), High (500/400 MW). All scenarios maintain existing/planned trades to Kenya (400 MW), Djibouti (300 MW) and Tanzania (300 MW), with Ethiopia prioritizing Sudan/Egypt exports over Kenya, Djibouti and Tanzania. The Sudan–Egypt interconnector is assumed upgraded to enable the specified trades. GERD filling follows a staged plan adapted from the Washington proposal and real-world progress; initial filling is nearly complete by 2024/2025. Long-term operation begins when GERD storage reaches 49.3 bcm: target 1,600 MW when 49.3–72 bcm, and full capacity above 72 bcm, with minimum daily environmental flow of 43 million m³ when physically possible. In trade scenarios, GERD releases are governed by power balance (no additional water-release constraints beyond environmental flow). Karadobi upstream dam filling (2032–2036) is included with scaled stage targets; steady-state target 800 MW. Hydrology and demand: Thirty 20-year hydrologic traces generated via the Indexed Sequential Method (ISM) from 1972–2002 capture interannual variability. The HAD initial storage is set at 162 bcm (satellite altimetry). Electricity demand growth projections derive from EAPP sources; price assumptions use US$0.05 kWh⁻¹ for existing Ethiopia–Sudan trade and US$0.07 kWh⁻¹ otherwise. Financials: Ethiopia’s export revenues and Sudan/Egypt net savings are computed considering displaced thermal generation costs and import prices.

Water outcomes: Increasing Ethiopia–Sudan/Egypt power trade reduces downstream irrigation deficits by inducing higher GERD turbine releases. Across 30 hydrologic traces, peak annual irrigation deficits are reduced in Egypt by up to 5.1 bcm and in Sudan by up to 1.3 bcm. Specifically relative to the Washington draft proposal, Egypt’s maximum annual irrigation deficit decreases by 4.0, 1.87, 1.7 and 1.9 bcm in the High, Medium-high, Medium-low and Low trade scenarios, respectively, and the probability of an annual deficit declines by 1.7%, 10.3%, 16.5% and 15.2% (same scenario order). Sudan’s peak annual deficit falls by roughly 1.3 bcm; the probability of Sudanese annual deficits is already low relative to its 15.16 bcm annual supply. High Aswan Dam (HAD) operations improve: Weeks in drought-management zones decline sharply with more trade. Weeks in Zone 1 drop by 4%, 32%, 64% and 96% and in Zone 2 by 26%, 67%, 90% and 98% for Low, Medium-low, Medium-high and High scenarios, respectively, with more time in the normal zone, implying fewer Egyptian irrigation shortages. Under a dry sequence (1977-like), the initial GERD filling lowers HAD storage but does not cause Egyptian irrigation deficits due to high initial HAD levels; during steady state, higher trade keeps GERD lower and HAD higher, reducing Egyptian curtailments by up to 4.0 bcm/year (7.3% of demand) in the High scenario. Energy outcomes: Demand curtailment is reduced in Sudan as trade increases; Egypt experiences no curtailment in all scenarios; Ethiopia’s curtailment is similar across scenarios because exports occur after domestic demand is met. Hydropower generation increases with trade: Sudan’s total hydropower rises in 80% of traces; Egypt’s annual hydropower increases in 32%, 69%, 73% and 82% of traces from Low to High scenarios; Ethiopia’s annual hydropower increases in 65%, 90%, 96% and 97% of traces respectively. Ethiopia’s total annual hydropower increases by up to 9–10 TWh (Low/Medium-low) and 12 TWh (Medium-high/High). GERD’s annual generation increases by up to 6.0, 6.8, 9.0 and 10.1 TWh (Low to High) versus the Washington case, because drought-mitigation releases otherwise bypass turbines in the baseline. Thermal generation and emissions: Total annual thermal generation across Ethiopia, Sudan and Egypt declines (median) by 2.08, 3.48, 3.0 and 4.4 TWh (Low to High) relative to the baseline. Associated annual CO₂ emissions fall by 1.15, 1.98, 3.20 and 4.54 million tonnes (Low to High), with maximum reductions comparable to about 25% of Sudan and Ethiopia’s 2020 national emissions. Financial outcomes: Ethiopia’s annual export income (2026–2041) increases by US$71–128 million/year (Low) and US$296–498 million/year (High) relative to the Washington scenario, depending on hydrology. Sudan and Egypt realize net financial savings from displacing expensive thermal generation and importing lower-cost hydropower—approximately US$36 million/year (Low) up to US$369 million/year (High) at 3% discount rate. Regional trade-offs: Prioritizing Sudan/Egypt exports slightly reduces Ethiopia’s exports to Kenya/Tanzania; agreed trades to Kenya and Tanzania are met 95% and 90% of the time, respectively. Tanzania may see a small increase in curtailment (up to 0.2 TWh/year) in Medium-high/High scenarios.

The results support the hypothesis that cross-border electricity trade can transform a water allocation dispute into a multisector cooperation opportunity. By creating dependable demand for GERD power, higher trade drives turbine releases that stabilize downstream flows, improving HAD status and reducing Egyptian and Sudanese irrigation deficits. At the same time, coordinated energy-water operation increases hydropower generation in all three countries, displaces thermal generation and lowers CO₂ emissions, and yields financial gains for Ethiopia (export revenues) and for Sudan/Egypt (avoided thermal costs). Thus, the GERD’s operational debate shifts from strict water-release constraints to mutually beneficial, enforceable PPAs, reducing the salience of contentious water release rules. Minor trade-offs appear in the southern EAPP (slightly reduced Ethiopian exports to Kenya/Tanzania and marginal curtailment increases in Tanzania under high-trade cases), but the overall system benefits are substantial. The integrated modeling underscores how credible, quantified benefit-sharing can unlock agreements otherwise blocked by water-centric bargaining, offering a template for transboundary basins where hydropower, irrigation and energy systems are deeply interlinked.

An integrated, high-resolution river-energy simulation shows that structured electricity trade between Ethiopia, Sudan and Egypt can simultaneously reduce downstream irrigation deficits, increase hydropower generation, cut thermal generation and CO₂ emissions, and improve financial outcomes compared with a water-centric baseline (Washington draft proposal). The work demonstrates that technical, quantifiable benefit-sharing via energy trade can temper the Nile water conflict by aligning GERD operations with downstream reliability needs. Future research should incorporate climate change uncertainties into trade and operation strategies, investigate broader benefit-sharing forms (for example, regional agriculture, fisheries, industrial cooperation and logistics), and explore institutional and regulatory designs for durable, flexible PPAs and coordinated river-energy governance.

The analysis does not explicitly assess climate change impacts on Nile flows, despite wide uncertainty in projections. It assumes status quo consumptive water demands and specific PPA priorities and prices, and presumes timely transmission upgrades (for example, Sudan–Egypt interconnection). The weekly time-step with one representative hourly day per week and fixed 2020 renewable profiles may not capture all intra-week variability. Proprietary data constraints limited public access to some model inputs. Results depend on assumptions about GERD/Karadobi commissioning, filling and operating rules; real-world deviations could alter outcomes.