Switzerland needs electricity at the times people and businesses use it. A useful cost comparison must price that service.
Ask what a number buys, which costs it includes, and who carries the risk.
Start with the service
A solar installation, a reactor and a storage plant provide different services. Even two storage plants can have very different jobs. Cost depends on how much electricity they deliver, when they deliver it and how the investment is financed.
Generation costs, storage costs and duty cyclesBuild and run
What does the equipment cost over its working life, including upkeep, fuel and renewal?
Deliver when needed
What else is needed: networks, storage, reserve capacity or changes to demand?
Make it investable
Can the owner cover costs? Who carries delays, low prices and early closure?
Identify the payer
What reaches the customer bill, the taxpayer or another party to a contract?
These questions need separate accounts. Keep payments between parties separate from the resources consumed, so the combined total counts each cost once.
Cost ledger and accounting boundariesWhat LCOE and LFSCOE can tell us
Levelized cost of electricity, or LCOE, spreads the stated investment and operating costs over the electricity a plant is expected to generate. It accounts for the timing of spending and the assumed return on capital. It helps compare the cost of generation projects under stated assumptions. Market value and reliable delivery need separate analysis.
LCOE definition and limitationsLevelized full system costs of electricity, or LFSCOE, asks a broader supply question. In the inspected Idel manuscript, the main experiment requires a selected technology, with storage, to supply a market. It exposes the cost of covering gaps in that configuration. The author also tests wind with solar and a case allowing limited other supply.
Idel: model and alternative casesSwitzerland’s decision includes existing hydro, several generation sources, trade and different forms of flexibility. Pricing that mixed system requires a model with the relevant technologies and reliability requirements.
Single-source and mixed-system costsA fair national comparison uses the same demand and weather, then checks outages, networks, trade limits and project delivery. Its costs need a common scope.
For a closer comparison: equations, value and reliability
LCOE divides discounted expenditure by discounted net generation. Discounting converts future amounts to a common valuation date. State the plant life, rate, delivery point and residual value.
LCOS, the levelized cost of storage, uses discharged electricity as its denominator. Check whether charging electricity is included. Duration, cycling, losses and replacement assumptions must match.
The detailed LFSCOE discussion uses the complete February 2021 manuscript; changes in the final 2022 publication remain unverified. Its 95% variant concerns annual energy, not 95% of hours. Hourly reliability and outages still need their own tests.
Its restricted technology set, separate yearly designs, storage power-to-energy ratio and simplified outage/network treatment need checking before applying its results to Switzerland.
IEA’s VALCOE adjusts generation cost for energy, capacity and flexibility value. EIA’s LACE estimates avoided energy and capacity value. These add useful context but depend on their own system assumptions.
A portfolio comparison should price the future assets and operation needed to meet a common demand and reliability standard. Owner returns and household bills remain separate results.
LCOE, LCOS and avoided value · LFSCOE equations and limits · Value-adjusted cost · Metric definitions and comparison requirements
A Swiss price tag: rooftop solar
Start with a cost we can observe. A recent Swiss survey reports what installers offered or charged for rooftop solar. The price varies with size and scope.
CHF per kWp, excluding VAT · scale 0–3,500
A kWp is one kilowatt of rated peak solar power.
Coloured band: middle half of prices. Dark mark: median, the middle price. The band shows the spread of the surveyed prices.
- 2–10 kWp408 records2'497
- 10–30 kWp907 records1'911
- 30–100 kWp141 records1'428
- 100–300 kWp88 records1'102
- 300–1000 kWp47 records800
- >1000 kWp7 records660
The largest class has only seven records. Prices exclude important roof, external engineering and grid work, as well as batteries. Lifetime electricity costs also depend on output, finance, upkeep and replacement.
Price table and survey scope
| Size, kWp | Records | Lower quartile | Median | Upper quartile |
|---|---|---|---|---|
| 2–10 | 408 | 2'096 | 2'497 | 3'114 |
| 10–30 | 907 | 1'659 | 1'911 | 2'237 |
| 30–100 | 141 | 1'125 | 1'428 | 1'751 |
| 100–300 | 88 | 907 | 1'102 | 1'597 |
| 300–1000 | 47 | 705 | 800 | 1'010 |
| >1000 | 7 | 602 | 660 | 772 |
The survey combines 2025 offers and invoices within the rooftop installer's scope. Current procurement, alpine projects and ground-mounted projects require their own offers.
Moving from this price to a lifetime electricity cost needs more inputs: site output, useful life, financing, maintenance and replacement. Moving to reliable supply also needs the rest of the system.
Inputs needed for a generation-cost calculationCost and market value are different
Cheap production is useful. Its income also depends on when electricity reaches the market. An owner needs both a cost estimate and a credible account of what customers will pay.
Cost and avoided valueCHF/MWh · common scale 0–125 · 2026 Q1 and Q2
Solar
Hydro group
Wind
Biomass
Q1 is January–March; Q2 is April–June. Coverage is limited to the measured groups. The hydro sample covers selected categories, including run-of-river, diversion and drinking-water plants. The values cover those two quarters.
What the benchmark includes
BFE weights Swiss day-ahead prices by measured net injections. VAT, plant costs and complete capacity or flexibility value are outside these figures.
The hydro group includes categories such as run-of-river, diversion and drinking-water plants. Reservoir owners can earn different prices through their operating choices and contracts.
A plant’s profit also depends on its contract, own-use savings and costs.
Our planning rule: test generation against its own output profile and contracts. Value output at the times it reaches the market, and test how a large expansion could change prices. The storage backtest supplies a historical benchmark for that comparison.
Historical trading and commercial limitsFinancing changes the price of new construction
A capital-heavy project spends money before it sells electricity. The financing rate and the time until operation affect the revenue it must later earn. The example below isolates those effects under explicit assumptions.
Assumed new nuclear plant: CHF 10,000/kW before construction finance, 60 operating years and 90% utilization. The calculation uses analyst assumptions to isolate financing effects; a project decision needs a supplier offer.
At 7% real finance: 5 years to build → CHF 138/MWh; 10 years to build → CHF 159/MWh; 15 years to build → CHF 187/MWh.
Partial generation cost, CHF/MWh · common scale 0–350
The rate is above inflation. Subsidies and future cost reductions are set to zero. Grid, backup, taxes, full insurance terms and unresolved dismantling or fund costs are excluded.
All rates, formulas and missing costs
Money is spent evenly at annual midpoints during construction. Each payment carries financing costs until the plant opens. Longer construction also changes the payment schedule here; an idle delay is a different calculation.
Annual cost = financed capital × capital-recovery factor + CHF 120/kW fixed upkeep. Divide by annual output, then add CHF 15/MWh for fuel, variable costs and a waste allowance.
The capital-recovery factor is r ÷ [1 − (1 + r)−n], where r is the annual rate and n the operating years. Annual output is rated power × 8,760 hours × 90%.
Extra site overhead and replacement electricity during delays are excluded. A complete project assessment must add missing items and test outages, reduced use and different lifetimes.
| Real annual rate | 5-year build | 10-year build | 15-year build |
|---|---|---|---|
| 3% | 80 | 84 | 88 |
| 5% | 106 | 117 | 129 |
| 7% | 138 | 159 | 187 |
| 10% | 193 | 243 | 313 |
Our proposal: publish the construction price, spending schedule and financing terms together. Name who pays for delay, cost overruns and low output. Show the risk carried by public guarantees or subsidized loans separately.
Extending existing nuclear
Extending an operating reactor uses the existing plant. The extension calculation covers further investment, maintenance, fuel and future obligations. The Swiss study asks whether the additional income can cover those costs.
| Study case | Gösgen | Leibstadt |
|---|---|---|
| Planned extension to 80 years | 46 | 44 |
| Operate six months per year | 78 | 72 |
| Close after two extension years | 134 | 104 |
The study uses operator best-estimate investment costs and 7% nominal pretax finance. Nominal includes inflation; it differs from the real rate in the new-plant example.
The planned case assumes sufficient existing prefunding and no additional dismantling costs. Early closure includes continuing costs after shutdown. The estimates cover extensions of the existing reactors. Operation still requires safety approval.
Our assessment: these results support making safe, economically viable extension a serious option. The conditions matter: safety approval, realistic investment costs and enough operating years to recover them. A new reactor requires a separate construction and financing estimate.
Storage cost depends on how often it is used
A battery used most days spreads its fixed costs over more discharged electricity than one kept for rare events. That changes its cost per unit, even if both batteries cost the same to buy.
Cost including charging, CHF/MWh discharged · scale 0–3,000
A full cycle delivers the store's usable energy once. The assumed purchase cost is CHF 1.5 million; life is 15 years; finance is 7% real.
Rarely used backup can still have value. This chart prices discharged energy. Emergency availability has a separate value that needs its own estimate.
Charging, upkeep and use assumptions
Charging electricity costs an assumed CHF 40/MWh. At 85% round-trip efficiency, delivering one MWh requires buying about 1.18 MWh. Charging is counted once.
The annual cost allowance is 4% of purchase cost. It already includes operation and battery augmentation, which replaces lost capacity.
Annual discharged MWh = 4 × full cycles. Cost per discharged MWh = [capital recovery + annual upkeep] ÷ annual discharge + 40 ÷ 0.85.
All four cases fit within a necessary charging/discharging time budget. Achieving those cycles also requires charging electricity and suitable operating opportunities; income depends on the market and contracts. Site costs, taxes and full insurance terms remain incomplete.
For emergency readiness, ask what capacity is available, for how long, and what the buyer pays to reserve it. For regular energy trading, ask whether the price difference covers charging, losses, wear and ownership. Storage duty cycle and reserve service · Trading and ownership comparison
Who pays for reliable supply?
Hydro owners give up other opportunities when they reserve water. Storage owners buy charging electricity. Investors need to recover construction and renewal costs. Those obligations remain even when a national model can find a useful operating schedule.
Hydro opportunity cost and owner economicsPay for a specific service
Separate availability from delivered electricity. State the duration, delivery conditions and payment for each.
Count each cost once
Reconcile charging, construction finance, waste funds and reserve payments. Keep transfers separate from the underlying expenditure.
Keep participation viable
Use voluntary contracts that cover obligations and risks. Include hydro concessions and income lost from alternative water use.
Expose the downside
Show what happens when construction is late, a plant is unavailable, market prices fall or a dry year reduces output.
Our proposed action
Publish a costed winter-supply comparison.
Start from existing assets. Compare continued operation, new generation, storage, networks and voluntary demand flexibility against the same winter need.
Show total expenditure, reliable delivery and owner returns separately. Identify the customer or taxpayer obligation attached to each contract.
Apply the same tests to the current strategy and to a nuclear-inclusive alternative. Select projects on the combined cost, reliable delivery and commercial terms.
These comparisons inform individual investment decisions. A national cost estimate must combine them with the remaining generation, grid and supply requirements.
Data, assumptions and remaining boundariesReferences
- Generation cost, storage cost and avoided value
EIA · April 2026 methodology - Levelized full system costs of electricity: author manuscript
Robert Idel · February 2021 author manuscript - System costs and the value of power sources
Yuhji Matsuo / Energies · Published 2022 - Value-adjusted generation cost: IEA model documentation
IEA · Global Energy and Climate Model, 2025 - Swiss rooftop solar installation prices in 2025
Planair SA for EnergieSchweiz/BFE · 2025 offers and invoices; report dated 3 August 2026 - Swiss reference market prices: first two quarters of 2026
BFE · Publication dated 14 July 2026 - How Swiss reference market prices are calculated
BFE · Printed update: 1 April 2026 - Economics of extending Gösgen and Leibstadt to 80 years
BFE commissioned research · Report dated 12 March 2026; publication date not established - Cost comparisons: inputs, calculations and boundaries
WattInfo · Curated from the cost-metrics research package, 17 September 2026 - Storage owner economics: historical-price benchmark
Swiss Energy research project · Frozen research output
Find definitions, calculations and model inputs in the source register.