WEGAWOMB™
From one machine to a national system

What would it take
to power Kenya?

Start with Kenya’s recorded electricity demand, then explore an illustrative future portfolio of geothermal, hydro, wind, solar, and fuel-backed generation. Test energy and a difficult evening separately.

Screening model, not a grid design
Annual energy margin
—Delivery potential, not hourly service
Peak + reserve margin
—A selected-duration stress test
Illustrative annual cost
—Capital recovery + operations + fuel
Reliability verdict
UnverifiedAnnual totals cannot establish 24/7 service.

New: lower-loss recovery hub

Use the six-paper research brief to compare energy paths at the same delivered load. Keep conversion savings separate from grid power displaced by local sources.

Explore the architecture →

01Define the demand

Starting point: 11.32988 TWh recorded customer consumption and a 2.31620 GW system peak in FY2024/25. These measured benchmarks anchor an illustrative future scenario—not a reconstruction of the current grid.

Boundary: annual demand is recorded customer consumption; peak is a system-side measurement. Unrecorded use, off-grid demand, new connections, and future electrification are not added. Increase demand to explore them. The 10% physical grid-loss setting is an assumption, not a measured Kenyan rate.

02Choose the generation

An illustrative future portfolio—not Kenya’s existing fleet or a project recommendation. All capacities, annual factors, and peak contributions below are editable assumptions; geothermal replaces the U.S. nuclear example.

Generation capacity and annual and peak assumptions
Energy sourceCapacity
GW		Annual factor
%		Peak contribution
%		Annual energy
TWh

Default evening: solar 0%; wind 10%; geothermal 90%; hydro 35%; fuel-backed 90%. These are not accredited firm capacities. Hydro depends on water availability, geothermal on a suitable resource and plant, and fuel-backed generation on fuel supply. No imports are credited.

03Shift energy with storage

Batteries do not generate new energy. Their losses increase the generation needed, and their stored energy limits how long they can help.

Usable capacity is AC energy delivered by the battery. The peak screen assumes the chosen starting charge; it does not establish that charging is available before the event. Charging and discharging share the selected power rating.

04Keep the economics honest

Every cost below is an editable placeholder in constant U.S. dollars (USD)—not a researched supplier quote, a project budget, or a profit forecast. Full modeled generation costs are retained; surplus energy earns no assumed revenue.

Edit construction, operating, and finance assumptions
Generation cost assumptions; all illustrative and editable
SourceConstruction
$/kW		Fixed operations
$/kW-year		Variable + fuel
$/MWh		Cost recovery
years

Battery power and energy costs are complementary components, not two all-in battery prices. Battery life has its own capital recovery period; costs of replacements or degradation beyond that simplified annualization are not simulated. Grid investment and operating costs are placeholders, not a transmission plan.

How to use this

1. Change demand or the generation mix. 2. Compare the two margins. 3. Try the 72-hour stress test. 4. Review costs and the limits of the model before drawing conclusions.

GW measures power right now. GWh measures stored energy. TWh measures energy across a year. A positive energy margin does not mean electricity is available at every hour. Changes last until you reset or reload; download a report to keep your assumptions.

Sources, assumptions, and model boundary
  • EPRA FY2024/25 statistics, Table 2.3: 11,329.88 GWh recorded consumption. The system peak was 2,316.20 MW on 12 February 2025. This deliberately consistent baseline is not labeled as the latest data.
  • Kenya Power’s National Control Centre peak explanation: peak is a system measurement, not a summed customer-meter peak. The later July 2025 peak falls outside the baseline fiscal year.
  • Kenya Power FY2024/25 annual report, notes 7b and 8c: 14,472 GWh supply includes 1,534 GWh imports; 11,403 GWh sales include 73 GWh exports. These totals are not substituted for domestic consumption.
  • EPRA reports 23.36% annual-average losses and 21.21% at June/end-year. These accounting measures include technical and commercial losses; unbilled electricity is not all heat or recoverable energy. The separate 10% physical-loss assumption is not derived from these totals.
  • Every future generation capacity, annual factor, peak contribution, reserve, battery specification, and USD cost is hypothetical. Geothermal feasibility needs site-specific investigation; drought, fuel availability, and financing require separate studies.
  • No imports, off-grid generation, unrecorded consumption, future connection growth, hourly dispatch, emissions prices, permitting, or transmission routes are calculated. Standardized 8,760-hour planning year. Annual factors are not firm capacity credits.
Show the calculation rules
  • Annual generation (TWh) = capacity (GW) × annual factor × 8.76. Fractions use 0–1, not 0–100.
  • Battery discharge = usable GWh × annual cycles / 1,000. Charging = discharge / round-trip efficiency. Storage loss = charging − discharge. Battery discharge is never added as new generation.
  • Annual delivery potential = (generation − storage loss) × (1 − grid-loss fraction). Annual energy margin = this potential − annual demand. Actual hourly load served is not calculated.
  • Battery stress contribution = min(power GW, usable GWh × starting charge fraction / stress hours). Peak contribution at system supply = sum of generator GW × peak fractions + battery contribution. No additional grid-loss deduction is made against the supply-side measured peak. Annual customer delivery still deducts physical losses.
  • Peak target = system peak × (1 + reserve fraction). The chosen system peak must be at least annual average customer load / (1 − physical grid-loss fraction). The measured peak and recorded annual consumption have different boundaries; unrecorded use is not inferred. The peak screen assumes the same available generator power throughout the event.
  • Battery charging must not exceed annual generation; charging hours + discharge hours must not exceed 8,760 at the selected power. These are necessary checks only, not proof that energy is available at the right times.
  • Annual cost = capital × capital recovery factor for each asset + operating and fuel costs. CRF = r / [1 − (1 + r)−n]; at zero discount rate it is 1/n. Energy-accounted demand = min(annual demand, nonnegative delivery potential). The displayed $/MWh uses this annual-only denominator, which can overstate service and understate a reliability-adjusted cost.

Next engineering gate: regional, hourly demand and weather; validated storage dispatch; outage and fuel scenarios; grid stability and transmission studies; then a site-specific cost and permitting assessment. This planner is a conversation starter, not an investment recommendation.