Bengt J. Olsson
LinkedIn: beos
X/Twitter: @bengtxyz
AI summary
- The setup. At a 4 % WACC (75 % state-backed debt at 1 % real, 25 % equity at 13 %), almost no new nuclear is built without support, and offshore wind only up to 4.9 GW. From this baseline, either 5 GW of new nuclear or 8.9 GW of new offshore wind is forced into the 2040 Nordic system. Both give about 35 TWh per year.
- Same effect on prices. Both lower the Nordic load-weighted price by about 5 €/MWh, increase net exports by 19–20 TWh and cut consumers’ electricity bill by about 3 billion € per year. Both push out about 10 GW of solar, mostly in Denmark.
- Similar strike prices. The CfD strike price needed to break even is 81 €/MWh for nuclear and 79 €/MWh for offshore wind: the plant’s capture price plus the premium the model finds is needed.
- Higher top-up for offshore wind. Offshore wind sells most of its power when it is windy and prices are low (capture price 64 against 74 €/MWh for nuclear), so the direct CfD top-up is 15.2 €/MWh against 6.4 for nuclear.
- Higher loan support for nuclear. The loan guarantee is worth 29.9 €/MWh to nuclear and 13.5 to offshore wind, since nuclear needs more capital per MWh. It is not a payout: the state borrows and lends at 1 %, and its cost is the risk it takes on. In total, state support is 36 €/MWh for nuclear and 29 for offshore wind.
- System cost favours nuclear. The total system cost rises 4.2 €/MWh per forced MWh with nuclear and 9.5 with offshore wind (+149 against +329 million € per year). Nuclear also replaces 4.8 GVA of synchronous condensers and some onshore wind, because its generators provide grid strength.
- Welfare. Lower prices move money from producers to consumers, and the state pays part of the bill. What remains is the change in system cost: total welfare falls by 149 million € per year with nuclear and 329 with offshore wind.
- The caveats. 4.2 of the 5 GW of nuclear is built in Denmark, where nuclear power is banned today. The risk the state takes on through the loan guarantees has a societal cost, larger for nuclear, that is not included. Transmission grid costs are not part of the model.
- Conclusion. The two alternatives are roughly on par in this model. Future cost developments, grid costs, permitting and how well each fits new demand must be weighed alongside the CfD cost analysis.
In the previous post, some scenarios for loan subsidies to support nuclear and offshore wind power were explored. Depending on the assumed discount rate and investment costs, different amounts of the two were built. The central scenario was Scenario 3, with a 3 % discount rate and nuclear and offshore wind costs from Svk’s Långsiktig marknadsanalys 2026 increased by 25 % (and ten years’ construction time for nuclear). In that scenario about 9.5 GW of new nuclear and 3.6 GW of new offshore wind were built.
Here we look at the same problem from a CfD and total-cost viewpoint, at a 4 % discount rate, where almost no new nuclear is built without support, and offshore wind only up to 4.9 GW. Nuclear and offshore wind power costs are the same as Scenario 3 in the previous post (SvK LMA26 2040, increased 25% and assuming 10 years nuclear build time). The Nordic is treated as one country with six zones.
CfD cost components
The questions to answer then become:
- What is the strike price of a CfD that enables the build-out of the particular power production, given the used WACC?
- What is the premium the state needs to “top-up” to reach the CfD strike price level?
- What is the value of the loan guarantees in the two cases?
- What is the added system cost for the two cases?
The first two questions answer how much each project, nuclear or offshore wind, needs to receive in €/MWh for its produced energy in order to finance the project and get a return of equity to the desired level. The strike price is the price per MWh the forced capacity needs to break even at a 4 % WACC: the average market price (capture price) plus the support per MWh the model finds is needed (the premium).
The answer to the third question tells us how much interest saving the project receives yearly due to lower rate of the loans provided by the state. This is a “soft subsidy” since the state does not necessarily lose money, unless the projects fail. But the loan guarantees have an alternate cost in that they could have been used for other purposes.
The last question, about the total system cost, relates to efficiency of the complete system, and is a measure of the total welfare change in the system (consumer value – producer cost).
This is the kind of total system cost analysis that needs to be done when comparing different build-out scenarios, when only component LCOE does not give the whole picture.
In this case we will start from the point where the last blog left, in a comment that suggested that 3% discount rate was too low.
About the discount rate (WACC)
Assume the discount rate (WACC) is formulated like this: The owners finance the whole project, 75 % with debt and 25 % with their own equity. The state guarantees the debt, so it is raised at the government’s borrowing rate: 1 % real (3 % nominal − 2 % inflation). The equity carries the project risk and requires a higher return.
| Debt (state-guaranteed) | Equity | Real, pre-tax WACC | |
|---|---|---|---|
| Share of capital | 75% | 25% | |
| Previous post | 1% | 9% | 3% |
| This post | 1% | 13% | 4% |
The 3% WACC used in the previous post produced about 9.5 GW new nuclear and 3.6 GW new offshore wind. 9% return on equity may be enough for a state-guaranteed project, but in this post we will use a 4% WACC, corresponding to a high 13% (pre-tax) return on equity. The reason is both to have an even more conservative assumption on the WACC, and also that at this WACC, almost no new nuclear, and only 4.9 GW of offshore wind, is built endogenously, and we hence have to force in and subsidize these.
The new baseline thus “locks in” 0 GW new nuclear and 4.9 GW of new offshore wind power and optimizes the system around this (at the standard 6% discount rate for everything else), and provides a baseline total system cost. That is, in this 2040 baseline scenario there already exists 4.9 GW of new offshore wind power. This is important, since this “semi-new” offshore wind power 2040 will not receive the CfD support, because it is already included in the baseline.
From this baseline we do two variations:
- Force in 5 GW of new nuclear in the Nordic system, or instead
- Force in 8.9 GW of new offshore wind power (on top of the new 4.9 GW from the baseline)
Both will provide approximately 35 TWh per year in new energy, based on their capacity factors. But the total system costs will be different, as will the CfD subsidy amounts.
Results
The two forced power scenarios yielded the following results:
| Against the base (run667) | +5 GW nuclear (run673) | +8.9 GW offshore wind (run671) |
|---|---|---|
| Forced new energy (TWh/yr) | +35.8 | +34.5 |
| Electricity price, Nordic, load-weighted (€/MWh) | −4.9 | −4.9 |
| Electricity price SE / NO / DK / FI (€/MWh) | −3.2 / −2.9 / −8.7 / −7.7 | −5.0 / −4.2 / −9.2 / −2.5 |
| Consumers’ electricity bill (M€/yr) | −3,061 | −3,039 |
| Net export to the continent (TWh/yr) | +18.7 | +19.8 |
| Solar output (TWh/yr) | −10.6 | −8.9 |
| Curtailment (TWh/yr) | −1.7 | −0.9 |
| System cost (M€/yr) | +149 | +329 |
| CfD settlement, new capacity (M€/yr, mean) | +230 | +525 |
| Loan guarantee, new capacity (M€/yr) | +1,070 | +467 |
| Total state support (M€/yr) | +1,300 | +992 |
| Market revenue, existing offshore wind (M€/yr) | −174 | −252 |
| Per forced MWh (€/MWh) | Nuclear | Offshore wind |
|---|---|---|
| CfD strike price (volume-weighted) | 80.8 | 79.0 |
| Capture price, 1-hour dispatch (volume-weighted) | 74.4 | 63.8 |
| State support | +36.3 | +28.7 |
| of which CfD settlement | +6.4 | +15.2 |
| of which loan guarantee | +29.9 | +13.5 |
| System cost | +4.2 | +9.5 |
| Market revenue, existing offshore wind | −4.9 | −7.3 |
The results are quite interesting. Both alternatives provide about the same additional energy, about 35 TWh per year, and lower the average price by 5 €/MWh. Both increase net exports by 19-20 TWh. The customer collective thus earns the same, about 3 billion €/year. So it seems like there is no difference between the two alternatives. Well, let’s look at the costs, it will provide a mixed picture.
The CfD strike price becomes 81 and 79 €/MWh for nuclear and offshore wind, respectively (which is surprisingly close to what the Swedish delegation on new nuclear proposed). However, with a lower capture price for offshore wind, a higher direct subsidy, 15 €/MWh, is needed to cover for the price difference than for nuclear that only needs 6.4 €/MWh in direct support.
On the other hand, the loan guarantee subsidy is higher for nuclear, at 30 vs 14 €/MWh. Note however, that this is a “soft” subsidy, since the loan guarantee costs the state nothing as long as the project succeeds, but it is worth about 1 billion € per year to the owners: that is how much more the nuclear plants would cost to finance at 6 % instead of 4 %.
Looking at the total system cost, we see that it increases twice as much per added offshore wind MWh as per nuclear MWh. Thus the system provides the energy more efficiently with nuclear. Nuclear also replaces 4.8 GVA of synchronous condensers and some onshore wind, because its generators provide grid strength; offshore wind does not. The break-down is seen in this table:
| Against the base | +5 GW nuclear | +8.9 GW offshore wind |
|---|---|---|
| Capacity (GW) | ||
| Nuclear | +5.0 | 0 |
| Offshore wind | 0 | +8.9 |
| Onshore wind | −0.9 | 0 |
| Solar | −10.3 | −9.4 |
| Synchronous condensers (GVA) | −4.8 | +0.3 |
| CHP, district heating | −2.5 | −2.4 |
| Heat pumps and electric boilers | +0.7 | +0.5 |
| Cost (M€/yr) | ||
| Capital cost | +1,733 | +2,128 |
| Operation and trade | −1,584 | −1,799 |
| System cost | +149 | +329 |
| Per forced MWh | ||
| Forced new energy (TWh/yr) | 35.8 | 34.5 |
| System cost per forced MWh (€/MWh) | +4.2 | +9.5 |
Summary
In total, the difference can be broken down in welfare terms. Consumers win big on both CfD solutions. Producers lose this income but are partly compensated by the state through the subsidies (and by increased export). Consumers’ gain, minus the state’s support, minus the producers’ loss, equals the change in total welfare (which is negative here since the new power is forced into the system).
In total the nuclear alternative is less costly in welfare terms, than the offshore wind alternative. However, the difference is small, and could be altered, in both directions, by other assumptions.
| M€/yr | +5 GW nuclear | +8.9 GW offshore wind |
|---|---|---|
| Consumers (lower electricity bill) | +3,061 | +3,039 |
| State, CfD settlement | −230 | −525 |
| State, loan guarantee | −1,070 | −467 |
| Producers (remainder) | −1,910 | −2,376 |
| Total welfare (= −Δ system cost) | −149 | −329 |
It is interesting that in the public discourse, the high direct subsidy for nuclear, the “top-up” pay-out to get to the CfD strike price is often used as an argument against the nuclear proposition. But from the above we see that this component is more than twice as high for the offshore wind alternative.
The other publicly discussed “cost”, the loan guarantee subsidy, is twice as high for nuclear. But this is not a pay-out from the state to the producers. It is the value for the producers due to the state taking over a large part of the risk. The state earns no money on the loans: it borrows at 1 % and lends at 1 %. The cost to the state is the risk it takes on, not a cash outflow. However, that risk is associated with a societal cost that should be added to both alternatives, and more so to nuclear.
All-in-all the two alternatives are rather on par in this model. Future cost developments, transmission network costs, right issues, system stability performance, fit for demand (for example EV charging and AI data centers have different demand profiles) must all be considered in addition to the CfD cost analysis.