Simulate the enterprise before you commit
One twin across generation, water, grid, finance, commercial, assets and environment. Replay a past period or project the next three years, then read the outcome as a briefing rather than a dashboard.
Horizon
Project forward from next month under the stated assumptions.
Enterprise scenarios
Starting points across functions
Assumptions
Seven levers across the enterprise
Results recalculate live as you move a lever.
Briefing
Nov 2026 – Oct 2028 · Scenario projection against Current trajectory
10.2% of demand is unserved across the 24-month projection — about 2,721 GWh. The constraint is firm capacity, not price.
- 01Secure firm capacity before the next dry season; treat new connections as capacity-committed.
- 02The outcome moves most with tariff (±12% swings margin by $324m) — that assumption deserves the tightest evidence.
- 03Mitigate first: hydrology stress at the lake — owned by Water Resources & Renewable Energy.
Trajectory
Energy delivered in GWh · reference against scenario
- Current trajectory
- Scenario projection
- Scenario projection
Financial path
Revenue, fuel cost and cash position year by year
| Year | Revenue | Fuel & variable | Fixed & sustaining | Operating margin | Unrealised tariff | Cumulative margin |
|---|---|---|---|---|---|---|
Year 1 12 months from Nov 2026 | $679m | $366m | $192m | $120m | $21m | $120m |
Year 2 12 months from Nov 2027 | $669m | $366m | $192m | $110m | $21m | $230m |
| Total | $1,347m | $732m | $385m | $230m | $42m | $230m |
Unrealised tariff is billed energy the tariff lever does not recover. Cumulative margin is the cash position carried forward across the period.
Station-level results
Output, availability and fuel cost plant by plant
| Station | Type | Installed | Availability | Energy | Share | Fuel cost | Status |
|---|---|---|---|---|---|---|---|
Akosombo 1020 MW installed · 39% load factor | Hydro | 1,020 MW | 39% | 7,054 GWh | 29.5% | — | Water-limited |
Kpong (Akuse) 160 MW installed · 39% load factor | Hydro | 160 MW | 39% | 1,106 GWh | 4.6% | — | Water-limited |
TAPCO (T1) 330 MW installed · 76% available | Thermal | 330 MW | 76% | 3,746 GWh | 15.6% | $176m | Below plan |
TICO (T2) 340 MW installed · 80% available | Thermal | 340 MW | 80% | 4,062 GWh | 17.0% | $191m | At plan |
TT1PP 110 MW installed · 77% available | Thermal | 110 MW | 77% | 1,265 GWh | 5.3% | $60m | Below plan |
TT2PP 80 MW installed · 74% available | Thermal | 80 MW | 74% | 884 GWh | 3.7% | $42m | Below plan |
KTPS 220 MW installed · 81% available | Thermal | 220 MW | 81% | 2,661 GWh | 11.1% | $125m | At plan |
Anwomaso 250 MW installed · 79% available | Thermal | 250 MW | 79% | 2,950 GWh | 12.3% | $139m | At plan |
Navrongo 2.5 MW installed · 23% load factor | Solar | 3 MW | 23% | 10 GWh | 0.0% | — | Variable |
Lawra 6.5 MW installed · 23% load factor | Solar | 7 MW | 23% | 26 GWh | 0.1% | — | Variable |
Kaleo A + B 28 MW installed · 23% load factor | Solar | 28 MW | 23% | 113 GWh | 0.5% | — | Variable |
New solar (REDP / SREP) 40 MW added in period | Solar | 40 MW | 12% | 81 GWh | 0.3% | — | Commissioning |
Where it breaks
Risks the scenario surfaces, by owner
- Hydrology stress at the lakeHigh
Inflow at 72% of average converts directly into lost hydro energy and higher fuel burn.
Water Resources & Renewable Energy
- Thermal reliability below planHigh
Availability at 80% strands capacity the plan assumes can be dispatched.
Thermal Generation
- Demand growth outpaces committed capacityHigh
Growth of 5.2% a year compounds faster than the capacity in the pipeline.
Corporate Strategy
- Deferred maintenance spiralMedium
Spend at 88 of plan defers condition work that returns as outage risk later.
Technical Services
- Load shedding exposureHigh
10.2% of demand goes unserved across the period.
Grid & dispatch
- Drawdown below operating comfortHigh
The lake reaches index 42 at its lowest point.
Water Resources & Renewable Energy
Model & confidence
What this run assumes, and how far to trust it
Capacity basis: 1,180 MW hydro, 1,330 MW thermal, 37 MW solar, 2,547 MW installed (cited public figures). Demand base, tariff, fuel price, fixed cost and hydrology response are illustrative parameters.
Confidence: Two years out, demand and fuel paths begin to dominate.
Illustrative model. Parameters are demonstration assumptions, not VRA operating data; the reference series is a reconstruction, not a record.
Cross-functional impact
Every relevant function, measured against the reference run
| Function | Indicator | Reference | Scenario | Movement |
|---|---|---|---|---|
| Generation | Energy delivered Hydro plus thermal output against the reference. | 25033 | 23949 | deteriorates -4.3% |
| Grid & dispatch | Unserved energy Load not served after dispatch of available capacity. | 1191 | 2721 | deteriorates +128.5% |
| Water & environment | Lake level at end Closing lake position after period draw. | 68 | 42 | deteriorates -38.2% |
| Finance | Operating margin Revenue less fuel and fixed operating cost. | 297 | 230 | deteriorates -22.7% |
| Commercial | Revenue realised Delivered energy at the realised tariff. | 1394 | 1347 | deteriorates -3.4% |
| Assets & operations | Maintenance backlog Condition work deferred inside the period. | 171 | 172 | steady |
| People & safety | Overtime exposure Pressure on crews from deficits and backlog. | 603 | 1246 | deteriorates +106.7% |
| Environment | Emission intensity Thermal share of delivered energy. | 363 | 364 | steady |
Scenario comparison
Two saved runs, differences called out
| Measure | Outage season collision | Wet year, slow demand | Difference |
|---|---|---|---|
Energy delivered GWh | 11,402 | 25,750 | +14,348 · better |
Unserved energy GWh | 1,566 | 231 | -1,335 · better |
Operating margin $m | 129 | 270 | +141 · better |
Lake level at end index | 81 | 98 | +17 · better |
Maintenance backlog index | 137 | 99 | -38 · better |
| Binding constraint | Supply security | Cost recovery | constraint moves |
Saved runs
Revisit or compare a briefing you kept
| Scenario | Horizon | Period | Unserved | Margin | |
|---|---|---|---|---|---|
Wet year, slow demand Commercial | projection | Nov 2026 – Oct 2028 | 0 GWh | $1,260m | |
Outage season collision Firm capacity | projection | Nov 2026 – Oct 2027 | 940 GWh | $520m | |
Fuel price shock Cost | projection | Nov 2026 – Apr 2028 | 0 GWh | $150m | |
Accelerated renewables build Integration | projection | Nov 2026 – Oct 2029 | 180 GWh | $1,480m | |
2024 replay — dry year with plant trips Supply security | replay | Jan 2024 – Dec 2024 | 1,310 GWh | $210m | |
2025 replay — recovery year Commercial | replay | Jan 2025 – Dec 2025 | 120 GWh | $640m | |
Dry lake, rising demand Supply security | projection | Nov 2026 – Oct 2028 | 2,721 GWh | $410m | |
Dry lake, rising demand Supply security | projection | Nov 2026 – Oct 2028 | 2,721 GWh | $230m | |
Replay: a tighter year at the lake No binding constraint | replay | Nov 2025 – Oct 2026 | 104 GWh | $145m |