Keep Gösgen and Leibstadt, develop two new reactors, and secure the winter electricity still needed alongside them.
Electric heating and transport increase demand. Keeping productive plants reduces the supply we must replace, while new reactors add electricity through winter nights. Continued operation depends on safety and a viable investment case.
Demand and nuclear prioritiesWhy add new nuclear?
Our programme plans for about 94.2 TWh a year used by customers in 2050, before network losses. This is an electrification scenario, including a data center allowance, rather than a forecast. Demand changes with weather.
Demand scenarioThe chart shows how much electricity is still missing with different numbers of new reactors. Each pair of bars compares supply with imports and without them.
Additional electricity over the full year, TWh · common scale 0–24. The labels give the total after all modelled generation and storage.
No new reactors
1 new reactor
2 new reactors
3 new reactors
The no-new-reactor bars remove those units without replacing them. The next section tests a package that replaces them with extra solar and batteries.
Each new unit has the same capacity and a chosen 30-day annual maintenance stop. The third unit's stop extends into October; the first two stop in summer. Part of their winter-output difference comes from that calendar choice. A real fleet should schedule maintenance around system needs and equipment constraints.
Different maintenance dates and existing-plant closure
Moving the third unit's maintenance entirely to summer reduces this annual gap to 1.07 TWh with imports up to 2 GW. The matched additions below use that summer calendar. Summer-maintenance case
| New reactors | Winter gap TWh | Full-year gap TWh |
|---|---|---|
| 0 | 20.93 | 23.28 |
| 1 | 16.69 | 17.91 |
| 2 | 12.55 | 13.27 |
| 3 | 8.8 | 9.02 |
Where shortages also occur in summer, the winter value is one feasible seasonal allocation of the annual total. The case download includes all three weather years, import ceilings and fleet choices.
This physical comparison assumes each new unit is delivered. A third unit still needs a site, approvals, supplier commitment and viable finance. It is not a project schedule or a least-cost portfolio calculation.
Matched fleet definitions and all scenario results · Case results (CSV)
In this demanding-weather case with imports up to 2 GW, two reactors reduce the electricity still missing from 13.3 to 4.6 TWh over the year. We therefore recommend developing the first two projects now and assessing a third alongside other dependable winter additions.
Fleet comparisonWhat about more solar and batteries instead?
We tested a package without new reactors, adding 20 GWp of solar and 40 GWh of batteries instead. In the 2016/17 weather case, it leaves 8.2 TWh missing over the year, against 4.6 TWh with two reactors. But in the 2011/12 cold spell, it lowers the largest hourly gap further: 4.1 GW against 6.1 GW.
Matched alternativesA reactor adds winter energy; a battery stores electricity from another hour. Both can help, in different ways. The two-reactor package has the lower peak in the other two tested weather years. These hourly gaps are preliminary results: cold-weather heating, hydro turbine access and grid constraints need engineering checks before equipment is sized. This is one tested solar-and-battery package. Its physical results do not establish which investment delivers the best value per franc.
Compare reactors, solar, batteries and hydro across three weather years
2016/17 — winter energy pressure
| Fleet change | TWh / year | GW |
|---|---|---|
| Two new reactors: reference | 4.64 | 2.99 |
| Add a third 1.1 GW reactor | 1.07 | 1.91 |
| Add 10 GWp of ordinary solar | 4.11 | 2.98 |
| Add 40 GWh / 10 GW batteries | 2.58 | 1.49 |
| Add 240 GWh of lake capacity | 4.64 | 2.99 |
| Add 1 GW of constant winter supply | 1.32 | 1.99 |
| No new reactors; add 20 GWp solar and 40 GWh batteries | 8.17 | 3.45 |
2011/12 — severe cold spell
| Fleet change | TWh / year | GW |
|---|---|---|
| Two new reactors: reference | 3.52 | 6.15 |
| Add a third 1.1 GW reactor | 0.2 | 5.07 |
| Add 10 GWp of ordinary solar | 3.03 | 6.15 |
| Add 40 GWh / 10 GW batteries | 1.05 | 3.08 |
| Add 240 GWh of lake capacity | 3.52 | 6.15 |
| Add 1 GW of constant winter supply | 0.21 | 5.15 |
| No new reactors; add 20 GWp solar and 40 GWh batteries | 6.72 | 4.07 |
2021/22 — dry year
| Fleet change | TWh / year | GW |
|---|---|---|
| Two new reactors: reference | 3.08 | 0.98 |
| Add a third 1.1 GW reactor | 0 | 0 |
| Add 10 GWp of ordinary solar | 2.61 | 0.84 |
| Add 40 GWh / 10 GW batteries | 0 | 0 |
| Add 240 GWh of lake capacity | 3.08 | 0.98 |
| Add 1 GW of constant winter supply | <0.01 | 0.75 |
| No new reactors; add 20 GWp solar and 40 GWh batteries | 5.85 | 1.82 |
Develop the third-reactor option and buy peak relief separately. In the cold-spell test, the solar-and-battery comparator reduces the peak more than the two-reactor reference, but leaves more electricity to supply over the year. That is why both columns matter.
What changes, what is held fixed, and what is still missing
The reference retains Gösgen and Leibstadt and contains 53 GWp solar. All cases use recorded October water stocks. The third reactor has summer maintenance. Added solar has the same ordinary Swiss profile; it does not represent alpine panels or wind. The battery provides 40 GWh usable discharge, 10 GW power and 85% round-trip efficiency. It starts and ends empty.
Extra lake capacity adds no starting water, inflow or turbine power. Its small benefit here does not value projects that retain more water before October. The 1 GW winter supply is an ideal delivery assumption; its fuel, permits and owner are unresolved. Existing reactors continue in the no-new-reactor case.
These are different-sized investments, not a ranking per franc. Matched wind and alpine-solar profiles, delivered prices, lifetimes and grid costs are still needed for that comparison. All three weather years and zero-import variants are available in the download.
48 matched calculations and assumptions · Results and definitions (JSON) · Method · Calculation code (ZIP)
Water changes the winter supply we still need
The lakes help carry electricity into winter. How much water they contain in October changes how much additional supply is needed. Our two-reactor programme still needs extra electricity even when the model starts with nearly full lakes.
- 1Lakes can start nearly full3.09 TWh
The model chooses the starting stock and can use all the stored energy assigned to the natural reservoirs.
- 2Start with the recorded October water4.64 TWh
Use the stock recorded for this weather year. The remaining supply requirement grows.
- 3Keep water in reserve as well5.64 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 6.15 to 7.99 GW. Both cases start with the recorded water stock.
Their full-year energy gaps are 3.52 and 3.52 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.
Electricity suppliers need winter contracts sized for the water actually available. Hydro owners need payment for holding water and supplying it later. Our hydro priorities are Grimsel 4 for more turbine power, and Grimselsee enlargement and Mattmark’s proposed shift for more winter delivery. The current hourly cases give these future projects no extra supply credit. Their contribution depends on permits, construction, water rights and viable contracts. Hydro project services · Mattmark’s winter proposal
Electricity for the whole winter and power for the largest hourly gap
Energy: how much is missing?
4.6 TWh
Additional electricity over a year with 2016/17 weather. Think of the volume of water a tank must hold.
Power: how fast must it arrive?
6.1 GW
Largest hourly gap with 2011/12 weather. Think of how much water the pipe must carry at once.
Different winters set the two requirements. In the cold-spell year, the annual gap is 3.5 TWh; in the energy-short year, the peak is 3 GW.
Both cases include 53 GWp of solar, recorded October lake stocks and imports up to 2 GW. They assume planned maintenance without a prolonged outage. Cold-weather heating and access to hydro turbines need further engineering checks before these peaks can specify equipment.
How outages and heating efficiency change the requirement
| Operating assumption | Winter gap TWh | Full-year gap TWh | Largest hourly gap GW |
|---|---|---|---|
| Planned maintenance | 4.64 | 4.64 | 2.99 |
| A 90-day winter reactor outage | 6.5 | 6.5 | 4.07 |
| Less efficient heating in cold weather | 5.86 | 5.86 | 4.51 |
| Both the outage and poorer heating efficiency | 7.74 | 7.74 | 5.59 |
The outage removes one new reactor 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. It transfers the 2035 conversion increment to 2050 as a bounded sensitivity. 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 boundariesSolar, nuclear and lake assumptions
The data center allowance holds a published 2030 scenario constant through 2050, after removing growth already included in the sector baseline. Faster growth needs more supply. The solar capacity is a test input; sites, replacements, connections and buyers still need a viable programme.
Demand and solar boundariesTwo reactors still rely on winter imports
With two new reactors, the recorded lake water and imports up to 2 GW, the model needs at least 7.5 TWh from abroad over the 2016/17 winter to retain this level of supply. That minimum keeps the annual gap at 4.6 TWh and the largest hourly gap unchanged. Removing imports leaves 12.7 TWh missing over the full year.
Import dependenceThat is why two reactors are a first build programme, rather than the whole sovereignty plan. More domestic winter generation reduces our reliance on electricity being available abroad during the same difficult hours. Trade remains useful, but a contract needs both the electricity and a dependable route across the border.
Compare import limits, gross imports and net imports
Additional electricity over the full year, TWh · common scale 0–13. Winter totals are shown separately below.
| Import ceiling | Winter gap TWh | Full-year gap TWh |
|---|---|---|
| 2 GW | 4.64 | 4.64 |
| 1 GW | 8.25–8.45 | 8.45 |
| 0 GW | 12–12.65 | 12.65 |
Even at the 2 GW ceiling, the model needs at least 7.47 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 4.64 TWh uncovered in winter.
Even with the more generous free-lake assumption, gross winter imports span 7.43–7.45 TWh. That uses about 85% 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 4.79–7.45 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
Could the same system also export over the year?
| Weather | Minimum | Maximum |
|---|---|---|
| 2011/12 | -8.1 | +11.6 |
| 2016/17 | -8.1 | +8.5 |
| 2021/22 | -7.7 | +7.4 |
Each range fixes annual unmet electricity, the largest hourly gap and annual gross imports at the reference values. Exports can use up to 8 GW. Demand still remains uncovered: these are possible schedules, not forecasts of a complete supply plan. Actual trade depends on prices and foreign demand.
The range depends on how much surplus is exported rather than left unused, as well as how the plants and trade are scheduled. These are alternative model schedules, rather than predicted sales. Annual net exports and dependable winter supply are separate tests. Fuel supply, hydro rights and grid delivery also matter for sovereignty.
Export and sovereignty boundariesReplace Beznau before the new reactors arrive
Our working dates for new reactors are 2047 and 2050, each around 1.1 GW net. Beznau’s owner-announced retirement comes earlier. Electricity suppliers therefore need a separate replacement package, while owners develop the new plants. Proposed dates and plant size · Beznau’s operating intentions
- 2027–2030Prepare two reactor projects
Compare sites and designs. Establish the owner, suppliers and financing route.
- 2027–2033Contract the earlier winter supply
Secure regular electricity and separate outage cover before Beznau retires.
- 2032–2033Replace Beznau’s output
Owner-announced closure dates: unit 2 in 2032; unit 1 in 2033.
- 2030–2039Prepare Gösgen’s extension
Reach an evidenced safety and investment decision before its 60-year point.
- 2035–2044Prepare Leibstadt’s extension
Keep replacement supply available if continued operation becomes unviable.
- 2037–2047First new reactor
Assumed construction and commissioning period. Commercial operation in 2047.
- 2040–2050Second new reactor
Overlapping construction is needed for the assumed 2050 start.
The preparation windows are our proposed deadlines. Beznau’s dates are the owner’s announced intentions. The new-reactor dates are planning assumptions; extending existing reactors depends on safety and owner economics.
Dated programme, dependencies and cost assumptions Beznau: owner’s operating intentions
The new-reactor dates depend on the legal route, approvals, suppliers and financing. If a project slips, replacement-supply contracts must run longer. Further delay or cancellation remains possible. The 2035 chapter sets out the earlier supply package.
Sites, overlapping construction and staged investment
Work on the second unit must overlap the first to meet these dates. Shared teams and suppliers may help, but overlap commits the second project before the first has an operating record. Contracts should follow demonstrated design, construction and commissioning milestones, with a stop option if the evidence deteriorates.
Our budget assumes the same cost for both units. A repeat-build discount needs an actual offer.
Delivery and unit-cost assumptionsThe historical Beznau, Mühleberg and Niederamt dossiers provide a starting library for comparing sites. External hazards, cooling, water rights and grid connections need updating. The full two-unit site and infrastructure requirements need assessment.
Site dossiers and unfinished workDevelopment funding should be released in stages. Before construction is ordered, the owner needs approvals, defined scope, supplier commitments and responsibility for overruns.
Financing changes what the electricity must earn
Our central allowance for two reactors is CHF 24.42 billion before financing, in 2026 money. This is an analyst budget. Supplier offers and site work must establish the committed price.
Construction allowanceLenders and investors also require a return for carrying risk. A higher required return means the plant must earn more from its electricity. The comparison below changes that return while keeping the construction and operating assumptions fixed.
Received electricity price needed to cover the modelled owner costs over the plant’s life. Common scale: CHF 0–320 per MWh.
- 3% required returnCHF 115/MWh
- 5% required returnCHF 153/MWh
- 7% required returnCHF 202/MWh
- 10% required returnCHF 300/MWh
Cheap finance is a condition to secure. A guarantee may reduce the owner’s financing cost while transferring risk to the guarantor. State that exposure alongside the lower electricity price.
The waste allowance covers handling and storage, with decommissioning funding separate. A geological-disposal contribution is not separately identified. These prices therefore require a complete disposal-cost assessment before they support a financing offer.
Waste-funding scope and required versus attainable revenue
What the owner calculation includes
Assume CHF 10,000 per kW of net capacity before financing, ten years of construction spending, and separate development, grid and initial-fuel allowances. Operation lasts 60 years at an assumed 85% average output.
The budget includes routine upkeep, fuel and variable costs, provisional insurance and waste allowances, a major refurbishment and decommissioning-fund contributions. Exact Swiss offers and insurance terms remain unresolved; uninsured accident exposure has no assigned price.
This is the average price the owner receives for its electricity. Customer bills also pay for networks, other supply and charges. The hourly model uses a separate maintenance calendar and availability assumption; its output is not multiplied by the financial 85% assumption.
The earlier construction-finance illustration isolates fewer cost items. This owner calculation uses its own, broader upkeep and funding assumptions.
Both units’ annual cashflows (CSV) · Construction, output and financing sensitivities (JSON)
Our recommendation is to seek priced financing options and long-term buyers before ordering construction. These prices assume the plants sell their stated output at the displayed price. Unsold electricity leaves less revenue to cover the owner’s costs. The nuclear chapter adds a disposal allowance and tests lower sales.
Capital range and the costs outside this reactor budget
The central allowance comprises CHF 22 billion for the plants and CHF 2.42 billion for development, grid connections and initial fuel. These allowances are assumed to be outside the plant price. An actual offer must remove any overlap. Changing the plant-cost assumption gives CHF 14.65–36.63 billion before financing.
Budget range and scopeHydro, solar, existing-reactor extensions, networks and backup need their own budgets. Published estimates use different price years and scopes. A national total requires comparable costs. The solar comparison prices larger fleets, summer sales, batteries and paid hydro shifting. Its seasonal nuclear reference uses different inputs from this owner budget.
Seasonal cost comparisonBackup needs fuel as well as a power station
Suppliers need regular winter electricity. Separately, reserve services need power available quickly and enough energy to cover a prolonged repair. An emergency plant’s power rating alone does not establish how long it can run.
Supplying the matched 4.6 TWh gap entirely with liquid fuel would need about 1.21 billion litres. The example assumes 40% net efficiency and 9.6 kWh of fuel energy per litre. A prolonged supply plan needs replenishment, not just a fuel tank.
Fuel calculationWe support fuelled backup where it remains necessary, with fuel availability, emissions, costs and operating permission explicit. Emergency reserve plants need permission for ordinary supply before they can be counted on for regular winter sales.
What the proposed reserve contracts cover
The proposed reserve contracts cover 583 MW and require fuel equivalent to 16 full-load days. That corresponds to 0.224 TWh of electricity. This is a future contract requirement, rather than a measured fuel stock today. Reserve proposal, sections 3.2.3 and 3.2.10 · Full-load energy calculation
Our proposed next decisions
Start the projects. Secure the supply between them.
- Plant owners: prepare Gösgen and Leibstadt extension decisions and staged development of two new reactors.
- Electricity suppliers: obtain winter-supply offers before Beznau retires, allowing for low lakes and limited imports.
- Plant owners and suppliers: compare a third reactor with hydro, storage, imports and fuelled backup for the winter electricity still missing. Buy power for the difficult hours separately.
Construction commitments need credible prices, approvals, finance and delivery responsibility. Hydro, storage and reserve owners need viable contracts for their services.
Data, calculation code and remaining uncertainty
The calibrated comparison tests three selected weather years. A separate 2035 free-lake comparison covers thirteen weather years. These samples do not establish probabilities or a final reserve margin.
The model pools reservoirs, knows future weather and omits internal grid constraints. Actual hydro cascades, owner access, cold-weather heating and dependable import or fuel contracts can change the result.
No outage probability is assigned. The 2050 stress cases remove one new reactor; the 2035 cases remove Leibstadt. Outage totals already include the underlying need.
Private construction, insurance and financing terms remain unresolved. The financial allowance cannot price an unknown liability as zero.
Calibrated inputs and cases (JSON) · Matched supply results (CSV) · Supply calculation method · Source catalogue (JSON) · Supply calculation code (ZIP; archived inputs acquired separately)
Separate owner cashflows (CSV) · Finance and original programme assumptions
Continue to the strategy summary and proposed policy choices.
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 - 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 - Nuclear construction records and conditional Swiss delivery cases
WattInfo · Delivery evidence, 17 September 2026 - Historical nuclear proposals: selected data and reuse assessment
WattInfo · Historical proposals, reviewed 18 September 2026 - Convention on Nuclear Safety: tenth Swiss report
Swiss Federal Nuclear Safety Inspectorate (ENSI) · Tenth report - Economics of extending Gösgen and Leibstadt to 80 years
BFE commissioned research · Report dated 12 March 2026; publication date not established - Visual explanations: seasonal stress, demand and storage
WattInfo · Visual chapter data and explicit teaching assumptions - Mattmark: proposed dam raising
Axpo · Published 2025-01-16 - Reserve financing: cost boundaries and fuel obligations
Federal Council · 2026-06-12 - WattInfo archive-to-model checks: demand, thirteen weather years and heat storage
WattInfo · Additive model evidence review, 18 September 2026 - Winter solar: capacity, seasonal costs and paid storage
WattInfo · Conditional component comparison, 22 September 2026 - Supply scale, fuel and nuclear owner-cost sensitivities
WattInfo · 2026-10-02 - Matched electricity, peak-power and trade comparisons
WattInfo · 2026-10-02 - WattInfo proposed supply path: decisions and supporting calculations
WattInfo · Proposed priorities and fixed-charging supply screen, 18 September 2026
Find definitions, calculations and model inputs in the source register.