Beznau’s announced retirement comes before the new reactors in our schedules. Our 2035 package keeps Gösgen and Leibstadt, expands solar to 26 GWp, and retains hydro and imports up to 2 GW.
In a demanding winter, that still leaves electricity to buy. The amount depends strongly on the water in the lakes each October. Electricity suppliers should seek offers across that range and buy emergency cover separately.
Retirement and conditional new-reactor datesContract winter supply against the water Switzerland can actually use. For 2035 demand and 2016/17 weather, nearly full lakes leave a winter gap of 3.1 TWh. Recorded October stocks increase that gap to 4.6 TWh. Retaining water equivalent to 1 TWh in the natural reservoirs raises it to 5.6 TWh.
These scenarios include planned maintenance, the data center allowance and up to 2 GW imports. The 1 TWh buffer is an operating assumption. A prolonged reactor outage and unavailable imports require additional cover. Matched winter supply cases and water assumptions
Put a first package on the table
Our reference case uses 73.5 TWh of annual end-use electricity in 2035, before grid losses. It follows the central electrification path in our sector-by-sector demand calculation. Weather changes the annual total and the hourly peaks. The separate data center allowance below raises the annual reference to 74.5 TWh.
Demand inputs and adoption assumptions 2035 calculation and hourly allocationKeep the remaining reactors
Gösgen and Leibstadt provide 2.243 GW of net capacity, subject to safe and viable operation. Include scheduled maintenance and arrange separate cover for exceptional outages.
Build useful solar capacity
Our proposed target is 26 GWp by 2035. From the estimated 2025 stock, that requires an average addition of 1.65 GWp each year.
Use hydro within its limits
Keep finite reservoirs and pumping capacity. Pay owners for useful services. Add project benefits as their delivery and operating conditions become credible.
Secure the remaining supply
Retain trade, allowing up to 2 GW imports in the reference case. Add contracted winter delivery and backup; lower import access raises the requirement.
The planned-maintenance cases include scheduled reactor stops and an output allowance, with no prolonged outage. A separate severe test removes Leibstadt for 90 days in January–March. That duration and timing are chosen assumptions. They test prolonged loss of a large plant during winter; no occurrence probability has been estimated.
Planned maintenance and the chosen prolonged outageThe reactor record includes prolonged outages; our contingency has no assigned frequency.
Package inputs and operating assumptions
The package retains thermal and wind output at the observed 2024 monthly levels, with an assumed delivery adjustment. It requires those sources to remain viable. No additional stationary battery or fuelled reserve is credited yet.
Monthly thermal and wind generationHydro expansions can provide valuable winter flexibility. Raising a lake can shift electricity between seasons without adding the same amount to annual generation. The first calculation gives no extra supply credit to hydro projects awaiting delivery. The hydro chapter tracks the project benefits and delivery limits.
Hydro projects: energy, storage and deliveryNew nuclear belongs in the longer-term programme. Our fastest illustrative schedule reaches commercial operation in 2042, with substantial dependencies. The 2035 package therefore needs its own supply contracts before a successor reactor can contribute.
Conditional reactor delivery schedulesBuy regular supply and arrange separate outage cover
We recommend three distinct services. Each needs its own delivery terms and price.
Regular winter electricity
Cover demand through ordinary operation, scheduled maintenance and difficult weather. Contract the remaining seasonal energy, with room for demand growth.
Immediate backup
Keep power ready to respond when a plant suddenly stops. Response speed, grid access and available power determine this service.
Prolonged-outage cover
Arrange sustained replacement supply if repairs take weeks or months. Price readiness separately from activation, fuel and delivered energy.
- 1Lakes can start nearly full3.07 TWh
The model chooses the starting stock and can use all the stored energy assigned to the natural reservoirs.
- 2Start with the recorded October water4.63 TWh
Use the stock recorded for this weather year. The remaining supply requirement grows.
- 3Keep water in reserve as well5.63 TWh
Use the same recorded start and retain water equivalent to at least 1 TWh in the natural reservoirs.
Seek winter offers across this range, with the water service priced explicitly. The 1 TWh floor is an assumed operating buffer. The model pools lakes and knows the weather in advance; actual rights, reserves and river connections constrain delivery.
Energy and power need different contracts
In 2011/12 weather, limiting natural-hydro turbine access to 80% raises the largest hourly gap from 1.25 to 3.09 GW. Both cases start with the recorded water stock.
Their full-year energy gaps are 3.34 and 3.34 TWh. Water quantity limits how much energy can be delivered; turbine access limits how quickly.
These hourly power gaps are screening results. Cold-hour heating, real hydro cascades and grid constraints need engineering assessment before reserve equipment is specified.
How outages and heating efficiency change the requirement
| Operating assumption | Winter gap TWh | Full-year gap TWh | Largest hourly gap GW |
|---|---|---|---|
| Planned maintenance | 4.63 | 4.63 | 1.35 |
| A 90-day winter reactor outage | 6.86 | 6.86 | 1.92 |
| Less efficient heating in cold weather | 5.93 | 5.93 | 1.75 |
| Both the outage and poorer heating efficiency | 8.16 | 8.16 | 2.33 |
The outage removes Leibstadt for January–March. It is a chosen stress test with no assigned probability. Each total includes the underlying shortage; adding rows would count energy twice.
The heating test assumes poorer heat-pump performance for newly converted space heating, especially in cold hours. The winter values describe one feasible dispatch; the full-year energy and largest hourly gap are the quantities minimised by the model.
The hourly gap describes power needed after planned dispatch. A sudden plant trip also needs fast response; these totals alone do not size that service.
Matched operating cases, heating assumptions and model boundariesAdditional electricity over the full year, TWh · common scale 0–4. These are historical weather tests, not probabilities.
The total includes any summer shortage. Different dispatch schedules can divide the same annual need differently between winter and summer.
The lake comparison above shows why actual starting stocks matter. A prolonged plant outage adds a separate supply requirement; its total already includes the gap during planned maintenance.
Thirteen weather years and calibrated generation assumptions
The planned-maintenance cases support buying additional winter supply before allowing for a prolonged outage. Their gap depends on the assumed output and hydro access. The severe-outage result includes that underlying need. Adding the two totals would count some energy twice. The hourly calculation does not size the fast-response reserve needed when a plant suddenly trips.
What each result can supportData center allowance already included
Add room for data center growth
The data center study’s central outcome adds 1 TWh beyond growth already counted in our demand path. The annual reference becomes 74.5 TWh in 2035, before weather variation and grid losses. The calibrated supply cases include this allowance. The calculation holds the study’s 2030 total constant through 2035 and spreads the additional demand evenly across the year. It assumes the matched existing demand sits in retained service-sector electricity. Further growth or a different hourly load profile changes the requirement.
Reconciled data center demand and mapping assumptionsThe demand chapter explains the existing load, study range and mapping assumptions.
Set contracts above the vulnerable assumptions
Price delivery with restricted imports as well as the reference case. The comparison below changes only the import ceiling within each operating case.
Additional electricity over the full year, TWh · common scale 0–14. Winter totals are shown separately below.
| Import ceiling | Winter gap TWh | Full-year gap TWh |
|---|---|---|
| 2 GW | 4.63 | 4.63 |
| 1 GW | 8.68–8.92 | 9.02 |
| 0 GW | 12.81–13.03 | 13.7 |
Even at the 2 GW ceiling, the model needs at least 8.26 TWh of gross winter imports to retain this level of annual supply. This minimum keeps both the annual energy gap and largest hourly shortage unchanged. That dependence remains after using the assumed domestic resources.
The import ceiling must be backed by electricity available abroad and a dependable route across the border. More domestic winter production reduces this reliance. Annual surpluses in sunny hours cannot supply a different hour by themselves.
How much imported electricity does the reference use?
This minimum holds the full-year energy gap and largest hourly shortage fixed. It allows annual imports and the seasonal split of shortages to change; this schedule leaves 4.63 TWh uncovered in winter.
Even with the more generous free-lake assumption, gross winter imports span 8.22–8.25 TWh. That uses about 94% of continuous delivery at the 2 GW ceiling.
Gross imports count electricity entering Switzerland. Net imports subtract exports in other hours; here they can span 7.84–8.25 TWh with the same annual shortage, peak gap and annual gross imports.
These are alternative feasible schedules, not trade forecasts. Annual imports are held at the saved annual import total; these endpoints do not establish the minimum possible winter imports under every trade policy.
Matched import ceilings, gross/net definitions and schedule ranges
The replacement chapter explains who buys each service, fuel requirements and Swiss reserve costs.
Buy energy and power as distinct services. Lower lake stocks raise the amount of electricity to secure. Restricted turbine access can raise the hourly power gap even when the seasonal energy changes little. The heating and outage table above compares those stresses on the same solar, reactor and lake assumptions. An operating plan also needs joint tests of restricted imports, cold weather and equipment failures before a final reserve commitment.
Matched sensitivities for supply offersDay, night and cars: an earlier illustration
The following illustration uses the earlier solar and reactor assumptions, before the separate data center allowance. It explains timing and compares vehicle services. Its savings cannot be subtracted from the calibrated gaps above.
Winter day
1'849 hours in this weather year
Peak demand: 18.0 GW
Winter night
2'543 hours in this weather year
Peak demand: 18.7 GW
Summer day
2'607 hours in this weather year
Peak demand: 15.6 GW
Summer night
1'785 hours in this weather year
Peak demand: 12.1 GW
Other sources must supply the rest. These bars compare demand with sunlight; they do not assign all solar output to Swiss consumption. Some surplus is stored, exported or curtailed.
This illustration uses the earlier solar and reactor assumptions, with no separate data center allowance. Its peaks depend on an assumed heating profile and need engineering checks. Use the calibrated cases for the current supply comparison.
The small solar amounts in the night bins come from dawn/dusk hour boundaries and regional sunrise differences.
How day, night and demand are counted
Winter is October–March. Daylight follows the Sun’s position at 47° N, 8° E, evaluated at each hour’s midpoint. Cloudy daylight remains daytime. Regional differences and hour boundaries can leave small dawn/dusk solar quantities in a night bin.
The model includes Gösgen, Leibstadt, historical hydro conditions, retained thermal/wind production and up to 2 GW imports. Vehicle demand keeps its fixed charging profile. Leibstadt is unavailable for 90 winter days. Pumping, exports and curtailment are separate from the demand bars. All four bins together cover the full year.
Perfect foresight and pooled hydro make this an optimistic national screening. Internal grid limits and commercial delivery need separate checks.
Full hourly flows, assumptions and calculations Day/night equations
How many cars will be available?
Vehicle replacement takes time. A high electric share of new sales does not immediately create an electric national fleet. The BFE study projects 2.1 million battery-electric passenger cars in 2035. Its early sales assumptions were faster than the outcome recorded in 2025. We therefore compare it with a simple turnover sensitivity anchored in the observed fleet and registration volume.
Fleet and sales assumptions, pages 16–18 2025 registrations and fleetBattery-electric cars already on Swiss roads.
Today’s sales volume; electric cars rise to all new sales by 2035.
The published 2023 scenario. Faster fleet electrification than our simple sensitivity.
BFS: observed fleet and registrations BFE: 2035 scenario, page 17 Turnover calculation and assumptions
Count the cars that can take part
The main example starts with the BFE scenario, then applies illustrative eligibility and participation assumptions.
- 2'100'000electric cars in the scenario
- 1'050'000compatible cars · assume 50%
- 525'000equipped homes · assume 50% of those cars
- 210'000willing participants · assume 40% of equipped owners
42'000connected during 08:00–17:59
assume 20% of participants
147'000connected during 18:00–07:59
assume 70% of participants
Local clock windows represent assumed connection behaviour. They differ from the sunrise/sunset split in the day/night chart. Parked cars without a working connection contribute no export power.
Fleet size also changes the electricity used for driving. With the stated driving and charging assumptions, the slower fleet uses 3.69 TWh a year for passenger cars; the BFE fleet case uses 5.2 TWh. Slower electrification also leaves more driving dependent on fuel. These separate fleet-energy tests replace the entire passenger-car component. The charging-service comparison below holds national demand fixed to isolate flexibility.
Whole-fleet electricity and case boundariesWhat changes between the two fleet cases?
The sales-paced case holds total cars and annual registrations at their 2025 levels. It assumes electric cars rise from 22.7% of new registrations to 100% in 2035.
Each year, it removes the same assumed share from the existing electric fleet and adds that year’s electric registrations. Young electric cars and older combustion cars will have different retirement patterns in reality.
The result is about 1.44 million electric cars in 2035. It is a sensitivity, not a fleet forecast. The BFE scenario uses a different stock model and adoption assumptions.
For the flexibility comparison, national demand remains the same. The lower fleet only reduces the pool that can take part. A separate transport forecast would also change travel-energy demand.
Three different services from the same cars
Smart charging moves charging to a more useful hour. The car takes electricity from the grid but does not send it back.
Vehicle-to-home, or V2H, lets the battery supply household demand. This can reduce the home’s evening draw from the grid.
Vehicle-to-grid, or V2G, exports electricity through an approved connection. Equipment, control and commercial arrangements must support that service. Vehicle-to-building uses the same principle for a larger building. Vehicle-to-load supplies appliances. We add neither as a second pool of the same cars.
Services, equipment and connection requirementsVehicle battery, travel and connection assumptions
In the example, each participating car has a 60 kWh usable battery. We protect 20 kWh and limit the working maximum to 50 kWh. The model also preserves electricity for 12,000 km of annual travel. Charging and export each have an assumed 90% efficiency. These are stated operating assumptions, rather than measurements of the future Swiss fleet.
Travel, battery limits and conversion lossesFor V2H, export is capped at an assumed 2 kW of local household demand per connected car. V2G permits 7 kW. The actual home load and connection must support those services.
Matched service limitsThe whole participating pool has a 6.3 GWh battery working window. Its assumed evening/overnight V2G power ceiling is 1.03 GW before national grid-loss accounting. Disconnected cars, travel needs and low charge can reduce what is available. The full battery window cannot be treated as firm grid storage.
Energy and connection limitsHome backup during a blackout needs a suitable installation. For example, Wallbox’s North American Quasar 2 specification requires additional hardware for backup. Check the actual car, equipment and local approvals before counting on that service.
Manufacturer example: separate backup hardwareWhat does vehicle flexibility change?
This vehicle comparison isolates charging services using its original solar and reactor assumptions and no separate data center allowance. Its savings cannot be subtracted from the calibrated supply gaps above without a matched calculation.
Smart charging removes 93.9 GWh of the gap. V2G removes a further 13.7 GWh. The higher V2G export limit adds almost no benefit over V2H in these tests.
These are optimized national energy benefits under the stated assumptions. Local network services and owner income can differ. Vehicles still require electricity for travel, and bidirectional conversion uses extra energy.
This earlier model has no separate data center allowance and uses its original solar and reactor assumptions. Peak results depend on the assumed heating profile and need engineering checks. Do not subtract these vehicle savings from the calibrated supply gaps.
All weather, import and fleet sensitivities
| Weather / service | Additional TWh | Peak GW | Gross imports TWh |
|---|---|---|---|
| 2012 · Fixed evening-heavy charging | 2.56 | 2.28 | 8.36 |
| 2012 · Smart charging | 2.46 | 2.11 | 8.33 |
| 2012 · Smart charging + V2H | 2.45 | 2.11 | 8.34 |
| 2012 · Smart charging + V2G | 2.45 | 2.11 | 8.34 |
| 2022 · Fixed evening-heavy charging | 2.31 | 0.70 | 8.66 |
| 2022 · Smart charging | 2.19 | 0.67 | 8.46 |
| 2022 · Smart charging + V2H | 2.17 | 0.66 | 8.37 |
| 2022 · Smart charging + V2G | 2.17 | 0.66 | 8.37 |
| 2024 · Smart charging + V2G | 0.00 | 0.00 | 4.41 |
| 2022 · Smart charging + V2G · no imports | 10.44 | 2.77 | 0.00 |
| 2022 · Smart charging + V2G · slower fleet | 2.21 | 0.68 | 8.43 |
| 2022 · Smart charging + V2G · no long outage | 0.00 | 0.00 | 8.23 |
The slower fleet changes only the number available for flexibility. National demand stays fixed so the contribution of flexibility can be compared. Peak gaps are minimized after annual missing energy; real operation may need more power. A zero model gap would still require grid and probabilistic reliability checks.
These vehicle comparisons include the exceptional 90-day Leibstadt outage. With the same proposed fleet and V2G assumptions, the 2011/12 case still needs about 2'448 GWh of additional supply. The 2021/22 case needs 2'170 GWh. The 2023/24 case has no material gap under these optimistic operating assumptions. Keeping several weather years avoids treating a favourable year as proof of reliable supply.
Matched weather cases and model limitationsIn the 2021/22 V2G case, removing the long reactor outage closes its modelled gap while still using substantial imports. Other weather years leave a gap with planned maintenance and no prolonged outage, as the fixed-charging comparison above shows.
Matched case without the long outageThis first package still relies on trade. The import tests above show why domestic supply and fuel resilience need further investment to meet our sovereignty objective.
Our recommendation: buy winter delivery, reward useful flexibility
Electricity suppliers should buy the missing winter energy, with water and import access specified. Arrange immediate backup and prolonged replacement supply separately. The calibrated cases guide requests for offers; joint stresses and engineering checks must precede final reserve sizing.
Matched quantities and boundaries Separate supply servicesIntroduce smart charging first. Buy bidirectional services where their added cost pays. A Swiss trial demonstrated grid services, but expected income did not cover the extra V2X costs in the studied business cases. Hydro and car owners need voluntary contracts covering wear, losses and forgone opportunities.
Demonstrated capability and commercial limits Owner costs and incomeThe supply tables include annual gaps because some cases also leave summer demand uncovered. The offers must cover those requirements too. Fuelled generation is a permissible fallback, with fuel stocks, emissions, permissions and costs explicit. Supplier offers are still needed to price the full package.
Annual and winter missing electricityCheck the model and reproduce the results
The separate vehicle-service model preserves hourly energy balance, finite storage and the cars’ driving electricity. It removes participating cars’ original charging allowance before adding their explicit charging, so travel is counted once. The calibrated supply cases keep fixed charging and credit no vehicle exports.
It optimizes the full year with perfect foresight. Natural hydro remains pooled; monthly inflows are smoothed. Vehicle availability is an aggregate envelope, with no individual trip simulation or internal grid model.
It first minimizes missing annual energy, then the peak gap, then imports and cycling. Several dispatch schedules can share those totals. Day/night allocations illustrate one solution.
The national demand path, fleet eligibility, equipment, connection behaviour and continued operation assumptions need further evidence. Cost optimization, contract profitability and the full 2050 construction programme remain separate assessments.
Regular supply and reserve interpretation
Calibrated supply method · Matched scenario results (CSV) · Calculation code and input manifests (ZIP; archived inputs acquired separately)
Baseline method before the separate data center allowance · Baseline cases and hourly inputs (ZIP)
Vehicle-service method and limitations · Inputs and results (JSON) · Reproduction bundle with all hourly flows (ZIP)
References
- Winter supply, lake access and nuclear fleet comparisons
WattInfo · Calibrated hourly scenarios, 26 September 2026 - Import reliance, winter solar inputs and forced shortages
WattInfo · Archived-input calculations, 25 September 2026 - Leibstadt annual report 2021: extended refurbishment
Kernkraftwerk Leibstadt · 2021 annual report - Return to grid after extended outage, 23 March 2026
Kernkraftwerk Gösgen · 2026-03-23 - Programme assumptions, dispatch choices and cost scope
WattInfo · Archived-input interpretation, 25 September 2026 - WattInfo electricity programme: 66 hourly cases, delivery dates and owner finance
WattInfo · Conditional programme, 19 September 2026 - WattInfo: regular winter supply, immediate backup and prolonged-outage cover
WattInfo · Supply-service interpretation, 18 September 2026 - WattInfo archive-to-model checks: demand, thirteen weather years and heat storage
WattInfo · Additive model evidence review, 18 September 2026 - WattInfo proposed supply path: decisions and supporting calculations
WattInfo · Proposed priorities and fixed-charging supply screen, 18 September 2026 - 2035 day/night supply and vehicle-flexibility model
WattInfo · First 2035 supply package and 12 matched/sensitivity runs - Independent demand model v1
Swiss Energy research project · Frozen research output - Swiss Electricity Statistics 2025
Swiss Federal Office of Energy (BFE) · 2025 - Swiss solar and associated storage statistics for 2025
Swissolar for BFE · Reference year 2025; report dated 9 July 2026 - BFE: monthly Swiss electricity balance, September 2026 snapshot
Swiss Federal Office of Energy · Snapshot retrieved 10 September 2026; HTTP last-modified 7 September 2026 - BFE / EBP: charging infrastructure and vehicle stock to 2050
BFE / EBP · 2023-05 - BFS: vehicle registrations and stock in 2025
BFS · 2026-02-04 - NOAA: solar-position equations
NOAA · Undated document retrieved 18 September 2026 - OST: bidirectional charging services and equipment
OST / Canton Zurich · Undated document retrieved 18 September 2026 - Wallbox: home-backup hardware requirement, North American equipment example
Wallbox · North America datasheet V1.2, 17 April 2024 - V2X Suisse: cars supplying grid services
Mobility and project partners / BFE · Final report dated 30 August 2024 - Nuclear construction records and conditional Swiss delivery cases
WattInfo · Delivery evidence, 17 September 2026 - Visual explanations: seasonal stress, demand and storage
WattInfo · Visual chapter data and explicit teaching assumptions - Storage owner economics: historical-price benchmark
Swiss Energy research project · Frozen research output - Reserve financing: cost boundaries and fuel obligations
Federal Council · 2026-06-12 - System Adequacy 2028, 2030 und 2035
ElCom · 2025-06-19 - Warum die Schweiz ein Stromabkommen braucht
Swissgrid · 2024-03-08 - Die Schweiz braucht das Stromabkommen
Swissgrid · Undated page; checked 2 October 2026 - Supply scale, fuel and nuclear owner-cost sensitivities
WattInfo · 2026-10-02 - Electricity Supply Act
Swiss Confederation · 2026-01-01
Find definitions, calculations and model inputs in the source register.