Energy Security and Self-Sufficiency Pathways: Between Capacity Expansion and Structural Dependence
The Permanent Condition of Energy Import Dependence
Energy security remains Mauritius' most binding structural constraint. As a small island economy with no domestic fossil fuel reserves, the country has historically relied on imported energy to power households, transport, industry, and services. This dependence, documented at over 80 per cent of total energy use in the mid-2010s, exposes the economy to external price shocks, foreign exchange volatility documented in Section 36, and supply disruptions entirely beyond domestic control. Despite repeated policy commitments to diversification and renewables, Mauritius enters the mid-2020s with an energy system that remains overwhelmingly import-dependent, only partially diversified, and—critically—insufficiently documented in public statistical form.
World Bank data 2012-2016, then discontinued
No publicly accessible data 2017-2025
15-20% of total import bill
The central challenge is therefore not merely one of energy transition, but of energy sovereignty: the degree to which Mauritius can reduce exposure to external fuel markets while maintaining reliable, affordable power for a services-heavy economy. This extends the "illusion of transition" analysis introduced in Section 38.2, where renewable deployment has diversified sources without materially reducing import dependence. The same pattern characterises energy policy at large: policy frameworks signal intent, capacity statistics suggest progress, yet structural reliance on external fuel markets persists—and the data infrastructure required to track whether this is changing has been allowed to lapse.
What can be stated with confidence is that there is no evidence of a structural break away from import reliance. All official planning documents continue to frame energy policy around managing, rather than eliminating, exposure to imported fossil fuels. According to publicly available summaries from the International Energy Agency, Mauritius' primary energy supply remains dominated by imported coal and oil, with modern renewable sources contributing roughly 10 per cent of final energy consumption.
Section 40.1Energy Use Structure: The Transport Blindspot
Understanding Mauritius' energy vulnerability requires looking beyond electricity generation to total energy use across all sectors. This reveals a critical blindspot in current policy discourse: the overwhelming focus on electricity obscures the fact that transport fuel—gasoline, diesel, aviation fuel—accounts for nearly half of all energy consumed, and remains 100 per cent import-dependent with no near-term substitution pathway.
Total Energy Use by Sector (Not Just Electricity)
The implications of this structure are profound and rarely acknowledged in policy discourse. Even if Mauritius achieved 100 per cent renewable electricity—an unrealistic scenario given grid constraints documented below—the country would still remain 70 per cent dependent on imported fossil fuels for transport, aviation, industrial processes, and non-electric uses. Electricity represents only 30 per cent of total energy demand. This means that renewable electricity deployment, while necessary, can at maximum displace roughly one-third of import dependence. The remaining two-thirds requires fundamentally different strategies: transport electrification, aviation fuel substitution, industrial process transformation, and demand reduction.
Consuming ~45% of total energy
25,000 new registrations annually
No charging infrastructure plan disclosed
Electricity Generation Mix and Thermal Dominance
Within the electricity sector specifically, the picture is one of gradual but limited diversification. Fossil fuels—coal and oil—continue to generate more than four-fifths of electricity output, with bioenergy (primarily bagasse from sugar production) contributing around 10 per cent and solar, hydro, and other modern renewables accounting for the remainder.
Mauritius Electricity Generation Mix (2024 Estimate)
The persistence of thermal dominance has direct implications for cost structures, emissions exposure, and vulnerability to fuel price volatility. Coal and oil are imported entirely, meaning that roughly 80 per cent of electricity generation remains tied to global commodity markets. When international energy prices spike—as during 2021-2022 and again in 2024 following geopolitical disruptions—these shocks transmit immediately into domestic energy costs, feeding inflation pressures documented in Section 36 and straining household budgets already burdened by food import costs documented in Section 38.
The Bagasse Question: Seasonal Biomass and Sugar Sector Decline
Bagasse from sugar production provides seasonal baseload contribution but faces structural constraints. Bagasse is only available during the sugar harvest season (July through December), meaning it cannot serve as year-round baseload. During off-season months, fossil fuel generation must compensate, creating operational complexity and limiting annual displacement. More fundamentally, bagasse generation is tied directly to sugar sector health—and the sugar sector has been in secular decline for decades, with land under cultivation shrinking, productivity stagnating, and economic viability increasingly questionable given land constraints documented in Section 37 and competition from global low-cost producers.
Expanding bagasse generation would require either agricultural intensification (increasing yields per hectare) or expanding cane cultivation—both unlikely scenarios. Land is scarce, water stressed (Section 37), and alternative land uses (urban development, tourism infrastructure, conservation) compete directly with agriculture. As sugar production declines, bagasse availability will likely follow, meaning this 10 per cent renewable contribution may erode rather than grow. Policy documents acknowledge this risk but offer no concrete pathway for sustaining bagasse generation long-term.
Section 40.3Capacity Expansion: Investment Costs and Payback Reality
The most concrete forward-looking evidence of transition comes from the Ministry of Energy and Public Utilities 2025/26 Programme Estimates, which for the first time publish explicit capacity targets. These represent meaningful infrastructure commitment, though understanding the full cost and payback timeline requires looking beyond capacity numbers to investment requirements and fuel savings projections.
| Technology | Capacity Target 2027/28 | Unit Cost (MW) | Total Investment Required | Technical Notes |
|---|---|---|---|---|
| Solar PV (Utility-Scale) | 300 MW | $1.0-1.2M/MW | ~$330M | Requires 750+ hectares land, grid integration, 20-25% capacity factor |
| Wind (Onshore) | 150 MW | $1.5-2.0M/MW | ~$270M | Coastal sites, tourism/conservation conflicts, 25-30% capacity factor |
| Bagasse (Upgrades) | 93 MW | $0.4-0.6M/MW | ~$47M | Depends on sugar sector viability, seasonal only (July-Dec) |
| Battery Storage | 50 MW / 100 MWh | $350-450K/MWh | ~$40M | Essential for intermittency smoothing, frequency support, peak shaving |
| Grid Reinforcement | System-wide | N/A | ~$150M | Transmission upgrades, distributed generation integration, smart grid |
| TOTAL INVESTMENT | 543 MW | — | ~$840M | Capital required 2024-2028 for target capacity |
Payback Analysis: How Long to Recover Investment?
The $840 million investment must be evaluated against fuel import savings to assess economic viability and payback period. Current annual fuel import bill for electricity generation estimated at ~$350-400 million (coal, oil, diesel for power plants). If 543 MW renewable capacity displaces 25 per cent of fossil fuel generation—a realistic scenario given capacity factors explored below—annual fuel savings would be approximately $85-100 million. At this savings rate, payback period for the $840M investment would be 8-10 years, not accounting for operations and maintenance costs, storage replacement cycles, or financing costs.
The Capacity-Generation Gap: Why 543 MW ≠ 543 MW
Perhaps the most critical distinction in understanding renewable electricity deployment is the gap between nameplate capacity (maximum theoretical output under ideal conditions) and actual generation (electricity produced and consumed over time). For fossil fuel plants, these figures largely converge: coal and oil plants run continuously at baseload, achieving 70-85 per cent capacity factors. For intermittent renewables—solar and wind—the gap is vast and often obscured in policy discourse focused on capacity targets rather than generation outcomes.
The Capacity-Generation Reality Gap
Nameplate capacity creates illusion of parity that actual output does not deliver
Why This Gap Matters for Policy Credibility
The capacity-generation distinction is not academic—it determines whether renewable targets actually reduce import dependence or merely create appearance of progress. A solar farm with 100 MW capacity might generate at 20-22 MW average output (20-22% capacity factor) given nighttime shutdown, cloud cover, and seasonal variation. Wind turbines face similar constraints: 150 MW wind capacity delivering ~40-45 MW continuous output.
This means that 543 MW renewable capacity by 2027/28 does not translate into 543 MW continuous generation displacing fossil fuels. At 25% average capacity factor, 543 MW delivers approximately 135 MW continuous equivalent—roughly 20-22% of a 600-650 MW generation system, not the 46% that capacity share implies. Fossil fuels continue generating 75-80% of electricity despite renewable capacity reaching 46%.
This is the core of what Section 38.2 termed the "illusion of transition": capacity expansion statistics create appearance of progress without demonstrating structural import displacement. Until the Ministry publishes generation projections alongside capacity targets—specifying expected kWh output, fossil fuel volumes displaced, and foreign exchange saved—the extent of actual energy security improvement remains unknowable to external observers. Capacity targets without generation outcomes function as political signals rather than verifiable milestones.
Renewable Resource Potential and Physical Limits
Even setting aside capacity factors and grid integration challenges, Mauritius faces hard physical constraints on how much renewable energy can be deployed. Unlike narratives suggesting unlimited renewable potential, small island geographies impose specific limits: land availability for utility-scale solar, suitable wind sites free of tourism and conservation conflicts, rooftop solar constrained by building stock, and grid capacity to absorb distributed generation.
Mauritius Renewable Potential Ceiling (Technical Maximum)
Utility-Scale Solar: ~400 MW maximum. Requires approximately 2.5 hectares per MW installed (accounting for panel spacing, access roads, inverters). 400 MW = 1,000 hectares (10 km²), representing ~0.5% of total land area (2,040 km²). However, this land must be flat, unforested, not in conservation zones, not prime agricultural land, and near transmission infrastructure. Given competing land uses documented in Section 37—urban expansion, tourism infrastructure, remaining agriculture, water catchments—finding 1,000+ hectares for solar farms represents significant challenge. Current target of 300 MW (750 hectares) already stretches available suitable land.
Rooftop Solar: ~150 MW maximum. Limited by building stock (residential, commercial, industrial), roof structural capacity for panel weight, grid connection capacity at distribution level, and economic viability (payback periods vary widely by tariff structure and consumption patterns). Current rooftop penetration <50 MW suggests reaching 150 MW ceiling would require near-universal adoption on suitable roofs—unlikely given cost barriers and grid integration constraints.
Wind (Onshore): ~200 MW maximum. Coastal sites offer best wind resources, but these overlap heavily with tourism zones, conservation areas (particularly southern coast ecological sensitivity), and residential areas where noise/visual impacts limit acceptance. Inland sites have weaker wind resources. Current target 150 MW approaching realistic limit without major tourism/conservation trade-offs.
Hydro: ~15 MW existing, no expansion potential. Rivers small, seasonal flow variability high, suitable dam sites already exploited. Water stress documented in Section 37 limits further hydro development.
Bagasse: ~100 MW theoretical maximum tied to sugar production. Current ~93 MW target near ceiling, and declining sugar sector may reduce availability over time.
Total Technical Ceiling: ~865 MW renewable capacity. Current target of 543 MW represents 63% of this maximum. Reaching the full ceiling would require resolving all land conflicts, accepting tourism/conservation trade-offs, near-universal rooftop solar adoption, and sustained sugar sector investment—none of which appear politically or economically likely in near term. The renewable transition has a hard ceiling below which policy ambition meets physical reality.
This resource ceiling has profound implications for long-term energy strategy. Even if Mauritius successfully deployed every technically feasible renewable megawatt—865 MW at 25% capacity factor delivering ~215 MW continuous output—this would displace at most 30-35% of current electricity generation, not 100%. Fossil fuel backup capacity must remain to cover renewable intermittency, evening peaks when solar drops, and low-wind periods. The notion of achieving 100% renewable electricity on current technology is physically constrained, not merely economically or politically challenging.
Section 40.6Grid Constraints, Storage Requirements, and the Stranded Asset Trap
The Ministry's programme documents explicitly acknowledge technical challenges posed by intermittency and peak-load demand, repeatedly referring to the need for battery energy storage and grid resilience. This acknowledgement is significant—it reflects institutional recognition that renewable deployment without storage and grid modernisation risks instability rather than security. Yet quantitative details remain sparse, exposing a critical gap between recognition and specification.
Storage: What's Actually Required vs What's Planned
No quantitative figures are published on existing battery storage capacity (likely minimal, under 10 MWh), planned storage additions in megawatts or megawatt-hours, or storage requirements for specific renewable penetration levels. International experience with isolated island grids suggests that achieving 30-40% renewable generation (not capacity) requires substantial storage:
• Daily smoothing of solar variability and evening peak management: 50-100 MWh minimum for Mauritius' ~450-500 MW peak demand grid. Solar output drops to zero after sunset (~6-7pm) while residential demand peaks (cooking, lighting, air conditioning), requiring stored solar energy to be dispatched during evening hours.
• Frequency support and grid stability for high intermittent penetration: Additional 20-40 MW fast-response batteries for frequency regulation as thermal baseload share declines, preventing blackouts from sudden generation/demand imbalances.
• Multi-day backup during prolonged low-solar/low-wind periods: Cyclones, extended cloud cover, or multi-day low-wind conditions require either multi-hundred MWh storage (economically prohibitive) or maintaining fossil backup plants at operational readiness. Most small island grids choose the latter—meaning fossil capacity cannot be retired even as renewable capacity expands.
The investment table in Section 40.3 estimated ~$40M for 50 MW / 100 MWh storage—sufficient for basic daily smoothing but inadequate for comprehensive grid stability at high renewable penetration. Achieving 40-50% renewable generation would likely require 200-300 MWh storage, costing $70-120M, not currently budgeted or planned in disclosed documents.
The Stranded Asset Problem: Fossil Capacity That Cannot Retire
As renewable capacity expands to 543 MW by 2027/28, total system capacity reaches 1,177 MW—more than double peak demand of ~500 MW. This creates a paradox: Mauritius will have enormous overcapacity on paper, yet cannot retire fossil plants because they remain essential for:
• Spinning reserves providing frequency support that batteries cannot yet fully replace at scale
• Backup generation during multi-day renewable droughts (cyclones, extended cloud/calm periods)
• Seasonal gaps when bagasse generation drops off-season
Cape Verde—closest comparable pursuing 50% renewable electricity—explicitly plans to maintain 60-70% of fossil capacity operational as backup and frequency support even at peak renewable deployment. Denmark, though grid-connected to continental Europe allowing power imports during renewable droughts, similarly maintains substantial dispatchable capacity (gas plants) that run at reduced utilization. Mauritius, with an isolated grid and no interconnection option, will face even greater need to preserve fossil backup—meaning the 634 MW thermal capacity in 2027/28 will remain largely intact operationally even as it generates declining share of kWh.
Section 40.7Transport Electrification: The 45% Blindspot
Returning to the total energy structure documented in Section 40.1, transport fuel remains the single largest energy end-use at ~45% of total consumption, yet receives minimal attention in published energy strategy. The vehicle fleet of ~450,000 is overwhelmingly fossil-fueled, with electric vehicle penetration under 1% (~3,000 EVs estimated in 2024). Annual new vehicle registrations average ~25,000, meaning that even aggressive EV adoption would take 15-20 years to turn over the fleet majority.
What Would Transport Electrification Require?
Ambitious 2030 Target (Not Currently Adopted): 30% EV fleet share by 2030 = ~135,000 EVs total, requiring ~20,000 EV sales annually (80% of new sales) starting 2025. This would require: Purchase price parity (currently EVs cost $10-15K premium vs equivalent fossil vehicles), comprehensive charging infrastructure (~2,000 public chargers, $5-7M investment), residential charging incentives, and competitive electricity tariffs making EVs economically attractive vs gasoline.
Grid Impact: 135,000 EVs assuming 15,000 km annual driving and 200 Wh/km efficiency = ~400 GWh additional electricity demand annually, or +50-70 MW average load. This would increase total electricity demand ~10-12%, requiring equivalent generation capacity additions beyond the 543 MW renewable target—capacity not currently planned. EV charging would also create new evening peak challenges (most charging occurs 6pm-10pm when solar output zero), requiring additional storage or demand management.
What's Not Addressed: Commercial vehicles (trucks, buses) where EV technology less mature and range constraints more binding. Aviation fuel (international flights ~15-20% of transport energy) with no near-term electrification or sustainable aviation fuel (SAF) pathway. Marine fuel (cargo, fishing, tourism boats) similarly lacking substitution options. Even with aggressive passenger vehicle electrification, transport sector likely remains 50-60% fossil-dependent through 2030.
No published government strategy documents specify EV adoption targets, charging infrastructure rollout plans, or integration of transport electrification into electricity generation planning. The Ministry of Energy focuses almost exclusively on electricity supply; transport falls under separate ministry with no apparent coordination on energy implications. This institutional fragmentation—echoing patterns in Sections 38 (food), 39 (ocean), and 36 (external accounts)—ensures that the single largest energy end-use remains strategically orphaned, unplanned, and unmeasured.
Section 40.8The Demand Side: Efficiency as the Forgotten Strategy
All preceding analysis has focused on energy supply: how to generate electricity, what fuels power vehicles, where renewables fit. Yet energy security has a second dimension rarely emphasized in policy discourse: demand reduction. International energy efficiency experience demonstrates that reducing consumption is typically faster, cheaper, and more certain than adding supply—yet receives far less policy attention and investment than generation projects that offer ribbon-cutting opportunities.
Efficiency Potential in Mauritius Context
Conservative estimates suggest Mauritius could reduce electricity demand 15-20% and total energy consumption 10-12% through efficiency measures costing fraction of supply-side investments:
Building Energy Codes: Requiring minimum insulation standards, efficient air conditioning, LED lighting, and solar water heating in new construction and major renovations could reduce residential/commercial electricity 8-10%. Investment: $20-30M in incentive programs and enforcement capacity. Savings: ~50-60 MW equivalent avoided generation capacity ($55-75M supply-side investment not needed), plus ongoing fuel savings.
Appliance Efficiency Standards: Minimum performance requirements for air conditioners, refrigerators, water heaters, and other major appliances—as exist in most OECD countries—could reduce electricity demand 5-7%. Investment: Regulatory framework development and market enforcement (minimal cost, under $2M). Savings: ~30-40 MW equivalent avoided capacity ($35-50M), plus annual fuel savings.
Industrial Efficiency Programs: Technical assistance and financing for energy audits, motor upgrades, process optimization, waste heat recovery in manufacturing, hotels, and commercial facilities. Investment: $15-25M grant/loan programs. Savings: 3-5% total energy use, particularly thermal fuels in industrial processes.
Peak Demand Management: Time-of-use electricity tariffs creating price signals to shift consumption away from evening peaks, smart meters enabling demand response, and utility programs incentivizing load shifting. Investment: $40-50M for smart meter deployment system-wide. Savings: 10% peak demand reduction (50 MW avoided peaking capacity worth $75-100M), improving grid stability and reducing need for expensive peaking plants.
The absence of published national energy efficiency strategy, mandatory building codes with energy performance requirements, or appliance standards represents a profound missed opportunity. Efficiency is not merely complementary to supply expansion—it directly reduces the scale of renewable infrastructure needed, shortens payback periods, lessens grid integration challenges, and provides the fastest pathway to reducing import dependence. That it remains policy afterthought signals disconnect between energy security rhetoric and actual strategic priorities.
Section 40.9Foreign Exchange Drain and Macroeconomic Transmission
One of the most consequential aspects of energy import dependence documented throughout this section is transmission into balance-of-payments stress (Section 36), inflation pressure, and fiscal vulnerability. Fuel imports—coal, oil, petroleum products—represent an estimated $420-480M annual outflow, or 15-20% of total merchandise imports. This makes energy the second or third largest import category after food and manufactured goods, yet it receives less systematic measurement and policy attention than either.
Annual Foreign Exchange Drain: Fuel Import Costs 2020-2025
This foreign exchange drain has multiple transmission channels: electricity generation costs rise when coal and oil prices spike, putting upward pressure on utility tariffs; transport fuel costs feed directly into CPI via petrol prices and indirectly through freight costs affecting all goods; and the balance of payments documented in Section 36 absorbs the import bill, constraining foreign exchange available for other imports or debt service.
What We Don't Know: Energy Data Gaps
Building on systematic data gap enumeration in Sections 39 (ocean economy) and throughout Section 40, this consolidation reveals what remains unmeasured, unpublished, or unavailable for rigorous energy security assessment. These gaps prevent independent evaluation of whether stated transition goals are being achieved and expose opacity as institutional choice rather than technical constraint.
UNPUBLISHED OR DISCONTINUED: Core Energy Security Indicators
These gaps concentrate precisely where transparency would expose uncomfortable realities: persistence of import dependence despite capacity expansion, unknown extent of fossil fuel displacement, unmeasured fiscal and FX costs of energy shocks, uncertain technical feasibility of ambitious targets, and absence of comprehensive strategies for transport (45% of energy use) and efficiency (15-20% potential reduction). Energy policy operates as narrative rather than accountable programme—ambitions declared without mechanisms for verification.
Section 40.11Comparative Island Energy Transitions
To contextualize Mauritius' trajectory, examining how other island economies with similar constraints have approached energy transition—and critically, how they measure and disclose progress—reveals not just technical differences but institutional choices about transparency and accountability.
| Jurisdiction | Energy Context | Renewable Achievement | Measurement & Disclosure |
|---|---|---|---|
| Iceland | Population ~380K, geothermal and hydro abundance, grid-isolated | ~100% renewable electricity (geothermal + hydro baseload, not intermittent) | ✓ Annual energy balance published, ✓ Generation mix detailed, ✓ Import dependence tracked, ✓ Transport still 100% fossil (85% total energy) |
| Cape Verde | Population ~560K, no fossil fuels, similar island constraints to Mauritius | ~50% renewable electricity target 2030, 15 MW / 7.5 MWh storage specified, wind + solar | ✓ National energy plan with quantified targets, ✓ Storage capacity published, ✓ Quarterly progress updates, ✓ Backup fossil capacity explicitly planned 60-70% |
| Seychelles | Population ~100K, heavily tourism-dependent like Mauritius, import-reliant | ~30% renewable electricity target 2030, solar + wind expansion, grid constraints acknowledged | ✓ Annual energy reports, ✓ Import costs disclosed, ✓ Renewable share tracked yearly, ✓ Diesel backup explicitly budgeted |
| Denmark | Population ~6M, grid-connected Europe, wind leader, relevant for technical modeling | ~80% renewable electricity (wind dominant), extensive storage and interconnection | ✓ Comprehensive grid integration studies, ✓ Capacity factors published, ✓ Storage roadmap detailed, ✓ Gas backup explicitly maintained |
| Mauritius | Population ~1.3M, no fossil fuels, grid-isolated, services economy, climate-vulnerable | ~10% renewable electricity current, 543 MW capacity target 2027/28, generation share unknown, transport 45% ignored | △ Capacity targets published 2025 (first time), ❌ Import dependence discontinued post-2016, ❌ Storage not quantified, ❌ Generation projections absent, ❌ Financing plan undisclosed, ❌ Transport strategy missing |
2029 Scenarios and Strategic Assessment
What emerges from Sections 40.0 through 40.11 is an energy system characterized by incremental progress within a fundamentally unchanged structure. Renewable capacity is expanding, institutions like the Mauritius Renewable Energy Agency are strengthening, and grid constraints are being acknowledged. Yet these steps occur within a framework where the most important indicators remain unmeasured, structural dependence persists, and transport—the largest energy end-use—remains strategically orphaned.
To ground expectations realistically, three scenarios project where Mauritius' energy system is likely to land by 2029 given current trajectories, investment constraints, and physical limits documented throughout this section:
The Realistic Case: 78-80% Import Dependence in 2029
The most probable outcome by 2029 is the realistic scenario: 480 MW renewable capacity delivered (12% below target due to permitting, financing, and construction delays typical in infrastructure projects), generating 22-25% of electricity (not the 40%+ capacity share implies), with fossil fuels continuing to provide 75-78% of grid power. Total energy import dependence—accounting for electricity plus transport fuel documented in Section 40.1—declines marginally from 80%+ (2016 last data) to 78-80% (2029 projected).
This represents measurable progress: ~60-75 MW of fossil generation displaced, annual fuel import savings of $60-75M, reduced emissions of ~500-600 kilotonnes CO₂ annually. Yet structurally, Mauritius in 2029 will remain overwhelmingly import-dependent for energy, vulnerable to the same external shocks that characterized the 2010s and 2020s, and constrained by the same macroeconomic exposures documented in Section 36. The transition will have begun, but energy sovereignty will remain distant.
What the Scenarios Reveal About Governance and Strategy
The narrow range between optimistic (75-78% import dependence) and pessimistic (80-82%) scenarios is itself revealing. Even perfect execution of current plans delivers only modest improvement. This reflects the structural constraints documented throughout Section 40: electricity is only 30% of total energy (Section 40.1), capacity factors limit generation (Section 40.4), renewable resource potential has hard ceilings (Section 40.5), transport electrification is unplanned (Section 40.7), and demand-side efficiency remains unaddressed (Section 40.8).
Five Strategic Imperatives for 2024-2029
First, restore comprehensive energy measurement and publish generation projections. Statistics Mauritius must resume annual publication of net energy import dependence (discontinued 2016), total energy use by sector, and fuel import costs. The Ministry of Energy must publish renewable generation projections (kWh, not just MW capacity), fossil fuel displacement estimates, and foreign exchange savings targets. Without transparent metrics, policy evaluation is impossible and accountability weak.
Second, develop integrated transport electrification strategy. Transport represents 45% of energy use yet remains strategically orphaned. A credible 2030 target—30% EV fleet share requiring ~20,000 annual EV sales—must be supported by charging infrastructure rollout (2,000 public chargers), financing mechanisms to address purchase price premium, and electricity generation planning accounting for +50-70 MW additional demand. This requires cross-ministry coordination currently absent.
Third, prioritize demand-side efficiency as least-cost pathway. Implementing building energy codes, appliance standards, and industrial efficiency programs can reduce electricity demand 15-20% at $75-105M investment—less than half the per-MW cost of solar generation and one-third wind. Efficiency delivers immediately, carries no fuel costs, produces no emissions, and reduces renewable infrastructure requirements. Yet receives minimal policy attention—a strategic misalignment favoring visible supply projects over cost-effective demand reduction.
Fourth, publish renewable infrastructure financing strategy. The $840M investment 2024-2028 documented in Section 40.3 requires transparent financing plan: debt vs equity, public vs private, concessional finance from climate funds, power purchase agreement structures, fiscal implications. Without disclosure, assessing whether transition is fiscally sustainable or creates debt vulnerabilities (Section 36) remains impossible. Investors and development partners require this transparency; its absence suggests financing strategy is incomplete or politically sensitive.
Fifth, confront stranded asset problem and transition costs. As renewable capacity expands, fossil plants will run at lower utilization but cannot be fully retired—creating upward tariff pressure from fixed costs spread over fewer kWh. Who bears these costs: consumers via higher tariffs, government via subsidies, utilities via write-downs? This distributional question will dominate energy politics through 2029 yet receives no published analysis. Transparent assessment of stranded assets, transition costs, and distributional impacts is prerequisite for durable political consensus supporting energy transformation.
Final Assessment: The Gap Between Aspiration and Execution
Mauritius' energy system at mid-decade is best described as incrementally transitioning within structurally unchanged constraints. Renewable capacity is expanding—from negligible pre-2015 to 543 MW targeted 2027/28, a genuine achievement. Yet this expansion occurs within a framework where total energy remains 78-80% import-dependent, transport fuel (45% of energy) lacks substitution pathway, demand reduction potential (15-20%) is ignored, and core measurement indicators discontinued after 2016.
The most important strategic conclusion is that energy security cannot be achieved through electricity sector action alone. Electricity represents 30% of total energy. Even 100% renewable electricity—physically unrealistic given grid constraints—would leave Mauritius 70% fossil-dependent. Energy sovereignty requires comprehensive approach: renewable electricity expansion yes, but also transport electrification, aviation fuel substitution, industrial efficiency, building codes, appliance standards, behavioral change, and transparent measurement enabling accountability.
Current strategy pursues comfortable incrementalism: capacity targets without generation outcomes, electricity focus without transport strategy, supply expansion without demand reduction, and measurement gaps preventing accountability. This produces visible progress (solar farms, wind turbines, ribbon-cuttings) without structural transformation. By 2029, Mauritius will likely have more renewable capacity but similar import dependence, modest fuel savings but persistent external vulnerability, policy ambitions repeatedly announced but hard choices deferred.
Section 40 therefore closes by positioning energy security as the ultimate governance test: not merely technical challenge of installing panels and turbines, but political test of whether the state can sustain long-term strategy requiring upfront costs, distributional conflicts, and patient capital over electoral cycles. The data gaps are choices, not constraints. The capacity-generation disconnect is knowable, not mysterious. The transport blindspot is institutional fragmentation, not technical inevitability. What remains unresolved is whether Mauritius will build the comprehensive strategy—spanning electricity, transport, efficiency, finance, and measurement—required for genuine energy sovereignty, or whether energy policy will continue operating as aspirational narrative disconnected from verifiable outcomes, joining food imports (Section 38) and ocean economy (Section 39) as major structural vulnerabilities tracked less rigorously than their strategic importance warrants.
Section 40 establishes energy security as comprehensive system challenge not reducible to renewable electricity: 80%+ import dependence persisting from mid-2010s (83.7% 2016 last data, 9-year gap) with $450M annual fuel import bill (~15-20% merchandise imports, ~$2.75B cumulative 2020-2025). Transport consuming 45% total energy—gasoline/diesel/aviation for ~450K vehicle fleet <1% EV penetration—strategically orphaned with no published electrification targets/charging infrastructure/grid planning. Electricity only 30% total energy meaning even 100% renewable electricity leaves 70% fossil-dependent. Renewable capacity expansion meaningful: 351 MW 2024/25 rising 543 MW 2027/28 (192 MW additions, 55% growth) requiring ~$840M investment ($330M solar, $270M wind, $47M bagasse, $40M storage, $150M grid)—but capacity ≠ generation due intermittency. At 25% capacity factor 543 MW delivers ~135 MW continuous output displacing only 20-22% electricity generation not 46% capacity share implies, fossil remaining 75-80% grid power. Physical constraints documented: renewable resource ceiling ~865 MW maximum (utility solar 400 MW limited by 1,000+ hectares land Section 37, rooftop 150 MW building stock limit, wind 200 MW tourism/conservation conflicts, hydro 15 MW exhausted, bagasse 100 MW declining with sugar sector), current target 543 MW = 63% technical maximum. Stranded asset trap: fossil plants cannot retire despite low utilization—634 MW thermal capacity must remain operational for spinning reserves/backup/frequency support creating unit cost pressure. Demand-side efficiency potential 15-20% reduction at $75-105M investment—less than half solar per-MW cost—ignored favoring visible supply projects. Three 2029 scenarios: optimistic (543 MW, 28-30% generation, 75-78% total import dependence, $90-110M fuel savings, 25% probability), realistic (480 MW, 22-25% generation, 78-80% import dependence, $60-75M savings, 60% probability), pessimistic (400 MW, 18-20% generation, 80-82% dependence, oil spike nullifies gains, 15% probability). Realistic case most probable: modest capacity delivery typical infrastructure delays, generation share limited by intermittency/storage constraints, total energy import dependence declining marginally 80%+ to 78-80%—structural continuity despite incremental progress. Strategic imperatives: restore measurement (import dependence/generation outcomes/fuel costs/FX drain), develop transport electrification strategy (30% EV 2030 requires 20K annual sales/2K chargers/+50-70 MW grid capacity), prioritize efficiency as least-cost pathway (building codes/appliance standards delivering more per dollar than generation), publish financing strategy ($840M debt/equity/concessional/PPAs fiscal implications opaque), confront stranded assets and transition costs (who bears thermal underutilization losses). Final assessment: energy security requires comprehensive transformation—electricity/transport/efficiency/finance/measurement—not electricity sector incrementalism. Current strategy comfortable: capacity without generation outcomes, electricity without transport, supply without demand reduction, gaps preventing accountability—producing visible progress (solar farms/turbines/ribbon-cuttings) without structural sovereignty. By 2029 more renewable capacity but similar import dependence, modest fuel savings but persistent external vulnerability, ambitions announced but hard choices deferred. Positions energy security ultimate governance test: technical capability present but political will for upfront costs/distributional conflicts/patient capital uncertain. Data gaps choices not constraints, capacity-generation disconnect knowable not mysterious, transport blindspot institutional fragmentation not technical inevitability—question whether state building comprehensive strategy or continuing narrative disconnected from outcomes.
Section 40 of 42 • Mauritius Real Outlook 2025–2029 • The Meridian