The Middle East and North Africa region confronts a critical juncture where failure to diversify electricity generation beyond fossil fuels could cost producer economies USD 80 billion in lost export revenues by 2035, while simultaneously inflating import bills for net energy consumers by USD 20 billion. This analysis emerges from the International Energy Agency’s examination of regional power sector trajectories, which reveals that maintaining current fossil fuel dependency rates of over 90% would require burning an additional 1 million barrels per day of oil and 180 billion cubic meters of natural gas annually—volumes that could otherwise generate substantial export income or feed higher-value industrial applications.
The stakes extend beyond fiscal impacts. Five countries—Iran, Iraq, Kuwait, Lebanon, and Saudi Arabia—would account for 80% of additional oil consumption in a scenario where renewable and nuclear deployment stalls. Saudi Arabia alone represents 40% of the potential increased oil use for power generation, reflecting both the scale of its electricity demand growth and current reliance on oil-fired capacity. For context, the kingdom already burns crude oil directly in power plants at rates averaging 720,000 barrels per day between 2021 and 2023, thereby forgoing refining margins that could add USD 5-18 billion annually, depending on product slate optimization.
Natural gas dependency intensifies the challenge. Egypt, Saudi Arabia, and the United Arab Emirates would absorb 60% of incremental gas demand under a high fossil fuel scenario, with these three markets collectively requiring an additional 110 billion cubic meters by 2035. The UAE’s position merits scrutiny—despite domestic gas production, the emirate imports pipeline gas from Qatar to meet power demand, creating supply chain vulnerabilities that accelerated renewable and nuclear deployment could mitigate.
Electricity demand trajectories amplify urgency. Regional consumption reached 1,440 TWh in 2023, having tripled since 2000, and projections indicate 50% growth to 2,160 TWh by 2035 under current policy frameworks. This expansion stems from compound factors: population increases of 85 million people by 2035, urbanization concentrating two-thirds of residents in cities, and cooling demand that already constitutes 23% of total electricity consumption. Critically, space cooling accounts for nearly half of peak demand—a figure that intensifies as temperatures rise 2.5 times faster than global averages, with some Arabian Peninsula subregions experiencing triple the global warming rate.
The cooling demand dynamic creates both challenge and opportunity. Peak electricity demand from cooling stood at 120 GW in 2023 and could exceed 240 GW by 2035 without efficiency interventions or supply diversification. However, this demand profile aligns temporally with solar photovoltaic generation peaks, offering natural integration potential. At a 25% capacity factor, displacing the 360 TWh currently generated from oil would require approximately 164 GW of solar PV capacity—an investment of roughly USD 70 billion at projected 2035 costs of USD 360/kW. Producer economies could recover this capital expenditure within 25 months through export revenues from redirected oil volumes, assuming 2023 price benchmarks.
Solar PV deployment has accelerated but remains concentrated. Regional capacity reached 18 GW in 2023, up from 3 GW in 2018, with Saudi Arabia contributing over one-third of growth through 2035 in the Stated Policies Scenario. Auction mechanisms drove this expansion, accounting for 60% of cumulative installed capacity, and delivered record-low bid prices—USD 12.90/MWh for 2 GW in Saudi Arabia and USD 14/MWh for 1.8 GW in the UAE. These figures reflect not just technological cost reductions but favorable financing conditions, state backing, and optimal land access unavailable across all markets.
Yet auction implementation timelines reveal systemic friction. From tender launch to commissioning, solar PV projects require three to eight years, with wind extending five to ten years. Egypt allocated over 40% of total lead time to auction administration alone, while Jordan’s sole wind auction consumed four years evaluating bids. Countries new to competitive procurement face steeper learning curves—Algeria has yet to select winners from multiple requests for proposals issued years prior. Bankability concerns further delay financial close, with contractual terms lacking sovereign guarantees or inflation indexation cited as barriers in Iraq’s inaugural auction.
Nuclear capacity expansion offers baseload diversification but faces different constraints. The UAE commissioned 4 GW across four reactors since 2020, while Egypt advances the 4.8 GW El Dabaa plant, targeting initial operations by 2027. Regional nuclear capacity could triple to 19 GW by 2035, yet this represents modest penetration given total installed capacity projections approaching 600 GW. Small modular reactor potential exists but hinges on cost reductions matching large-scale plants and successful commercial deployments expected around 2030.
Grid infrastructure emerges as a critical bottleneck. Transmission losses average 15% regionwide—double the 7% global benchmark—with Iraq experiencing 60% losses combining technical inefficiencies and non-technical factors including theft and inadequate metering. North African countries like Tunisia and Egypt report losses near 20%, constraining system efficiency despite generation capacity additions. The IEA estimates that addressing high losses represents one of the most cost-effective pathways to enhance energy security, yet investment requirements to modernize grids and reduce losses remain substantial.
Cross-border interconnection development proceeds unevenly. The GCC Grid links 950 km with 2.4 GW capacity, while the Mashreq Grid connects Egypt, Iraq, Jordan, Lebanon, Libya, Syria, and Turkey, though utilization remains suboptimal. The Egypt-Saudi Arabia interconnector launching in 2025 will provide 3 GW bidirectional capacity via the region’s first large-scale HVDC link, potentially enabling reserve sharing that exploits differing demand cycles. However, political tensions, regulatory fragmentation, and subsidy-distorted price signals continue to impede efficient cross-border electricity trade.
For net importers, fiscal vulnerability intensifies without supply diversification. Lebanon’s refined petroleum import bill reached USD 5 billion in 2024—25% of GDP—with projected cumulative additional costs of USD 50 billion through 2035 under a fossil fuel-intensive scenario. Jordan and Tunisia each spend approximately 7% of GDP on energy imports. These economies face double exposure: import price volatility and supply disruption risk, particularly acute given regional geopolitical instability.
Desalination compounds electricity demand pressures while demonstrating technological transition potential. Regional capacity of 40% of the global total produced 12 billion cubic meters in 2024, equivalent to the Euphrates River’s annual flow. Thermal desalination historically dominated, consuming 250 MJ per cubic meter versus 11-22 MJ for reverse osmosis. The last major thermal plant was commissioned in 2018, with all subsequent additions employing electricity-powered membrane technologies. This shift will triple electricity demand for desalination from 50 TWh in 2023 to over 160 TWh by 2035, yet reduce total energy intensity dramatically.
Efficiency interventions offer demand-side mitigation. Average air conditioner efficiency in MENA countries measures less than half Japan’s standard, and implementing robust minimum energy performance standards could reduce peak demand growth by 35 GW by 2035—equivalent to Iraq’s total generation capacity. Saudi Arabia’s 2022 window AC replacement initiative provides SAR 1,000 subsidies for efficiency upgrades, while Jordan’s Green Economy Financing Facility extends loans for appliance purchases. Building codes cover increasing shares of new construction—63% of residential floorspace additions in 2023 versus 38% in 2010—though renovation standards lag and informal construction persists.
Investment patterns signal gradual but insufficient rebalancing. Power sector spending reached USD 44 billion in 2024, projected to grow 50% by 2035, with low-emissions technologies capturing 35% of generation investment versus 30% globally. Gas-fired capacity additions will absorb 20% of global investment in that technology through 2035, reflecting continued fossil fuel centrality despite diversification rhetoric. Grid modernization and expansion account for 40% of total power investment, underscoring infrastructure deficits that constrain renewable integration.
Carbon intensity improvements occur despite generation growth. Emissions reached 950 million tonnes in 2023, but intensity declined from 700 gCO₂/kWh in 2000 to 530 gCO₂/kWh, driven primarily by gas displacing oil and coal. Under current policies, intensity falls to 330 gCO₂/kWh by 2035 even as electricity demand expands 55%, achieved through continued fuel switching, efficiency gains, and renewable penetration reaching 25% of generation. However, absolute emissions decrease only 10% by 2035—insufficient alignment with stated net-zero commitments from eight countries targeting 2050-2060 timeframes.
The Announced Pledges Scenario, assuming full implementation of national targets, projects radically different outcomes. Renewable capacity could approach 600 GW by 2035, solar PV share reaching one-third of generation, and low-emissions sources collectively supplying nearly 50% of electricity. This trajectory would halve power sector carbon intensity versus the Stated Policies Scenario but requires tripling investment to approximately USD 130 billion annually. Whether financing mechanisms, regulatory frameworks, and political commitment can sustain this acceleration remains the critical uncertainty.
Conflict-affected areas present distinct challenges where distributed generation offers interim resilience. Lebanon’s off-grid solar capacity reached 800 MW by 2024—potentially one-third of total installed capacity—driven by grid unreliability and diesel generator costs exceeding USD 400-500/MWh. Yemen’s decentralized solar deployment expanded fifty-fold during conflict as grid access collapsed below 10%, though lacking quality standards and technical support created sustainability concerns. These bottom-up responses demonstrate adaptive capacity but risk fragmenting system planning and complicating eventual grid integration.
The regional calculus ultimately hinges on opportunity cost recognition. Burning crude oil directly in power plants—720,000 barrels daily in 2021-2023—forfeits refining margins, adding USD 7-25 per barrel depending on configuration and crack spreads. Redirecting these volumes to petrochemical feedstock, export markets, or refinery optimization would generate USD 12-43 billion annually beyond baseline crude values. Natural gas faces similar value chain considerations, with industrial applications in aluminum, steel, and cement production offering higher economic returns than combustion for electricity.
The transition pathway exists but demands coordinated action across policy domains: accelerating auction implementation and reducing project development timelines; improving grid infrastructure and interconnection capacity; enforcing efficiency standards and building codes; reforming subsidy structures that distort investment signals; and mobilizing capital at scales matching stated ambitions. The alternative—maintaining 90%+ fossil fuel dependency amid surging demand—represents not just missed decarbonization opportunities but quantifiable fiscal losses and heightened import vulnerabilities that compound existing economic pressures. Whether the region’s diversification rhetoric translates to implementation velocity will determine if projected revenue losses materialize or are averted through accelerated clean energy deployment.
