Is Europe Ready for a Nuclear Renaissance?

This is a thought leadership report issued by S&P Global. This report does not constitute a rating action, neither was it discussed by a rating committee.

The European Union currently depends on nuclear power for about one-fifth of its electricity generation and 15% of its firm capacity (see Chart 2). The UK is also relying on new nuclear projects, namely Hinkley Point C (HPC) and Sizewell C (SZC), both comprising two plants with 3.2 GW of capacity each, to meet its legal commitment to reach net-zero by 2050 and to develop low-carbon dispatchable power and heat capacity. Several countries in Eastern Europe also rely on nuclear to decarbonize in the absence of potential for massive renewable penetration. That is the case for Czech Republic, Hungary and Slovakia. We also note that in Bulgaria and Romania, there is increasing interest for further nuclear development to complement potential offshore wind capacity.  

New nuclear projects are key to ensure plants due to be decommissioned by 2040 are replaced with sizable decarbonized capacity. As highlighted in the chart below, the European nuclear fleet is aging (the average reactor is 40 years old), which underscores the need for new builds to ensure that the share of firm and decarbonized power in the mix is not decreasing significantly. Commissioning of reactors over the past 30 years has been scarce in Europe (excluding Russia), which contrasts with the rest of the world, predominantly China, whose total nuclear power capacity is estimated to surge to above 110 GW from about 40 GW in 2010 (Transition Needs Will Energize China’s Nuclear Power Sector, S&P Global, April 22, 2022). For European new builds, we expect Western technology to be chosen (not of Chinese or Russian origin), including Korean technology. In France, European Pressurized Reactors (EPRs) dominate, which is a third-generation pressurized water reactor design, developed mainly by Framatome, now part of EDF. 

The construction costs of all recent new nuclear reactors, in Europe and the US, remain massive: we see the starting point of overnight costs (that is, ignoring the cost of capital during construction as if the project was completed "overnight”) at about or above an order of magnitude of €10 million/MW for Europe-built EPRs (it is unclear whether SMRs would be cheaper per MW; the real credit mitigant would be the three to four times lesser single-asset exposure if a utility is building just one).

Below are our rough estimates of overnight costs at the major recent nuclear new builds.

For the big Western reactors recently commissioned that started construction earliest, we thus estimate over €_{COD date}8 million/MW for Finnish OLK-3 (as heavy spending had taken place a decade before the 2023 commissioning) and €_{COD date}10 million/MW for French FLA-3.

• As a rough estimate, for North American Vogtle, which started construction a decade before its 2023 COD, the cost exceeds €_{COD date}11 million/MW.

The costliest of all by far is the very latest build, the UK's HPC. As per the latest (January 2024) public communication on current costing, we see about €₂₀₂₄15 million/MW.

For clarity, we include in “overnight costs,” beyond those capitalized by the developer, certain items which, given the magnitudes involved, can be very relevant:

• Pre-COD operating costs, which some developers expense, rather than capitalize, and nonetheless represent monies sunk before cash flows in. For example, for FLA-3 construction, operating expenditures (opex) of €1.14 billion (€0.7 million/MW) were expensed over 2022–2023 alone.
• Certain post-COD costs (e.g., the FLA-3’s vessel-head repair under first big planned outage) were an ASN (France’s Nuclear Safety Authority) precondition for commissioning in the first place. Both repair costs and the opportunity cost of not producing power during repair are not yet known.
• Supplier losses, like Toshiba’s $3.68 billion loss on Vogtle or Areva’s several-billion-euros loss on OLK-3. They are typically hard to assess (and typically excluded from the LCOE). The appropriate baseline for assessment is an arguable point: the downside from the reasonable return the supplier expected versus from a break-even point. Nevertheless, net losses should be factored into the analysis.

Even aside from the cost of financing (“cost of carry,” which only the “WACC-loaded cost” factors in), assessing an existing project’s costs requires reestablishing the consistency, over a long period, of €1 disbursed in 2010 versus €1 disbursed in 2024, so as to address the inflation impact. This is what we understand EDF does, enhancing transparency, when stating, for example, FLA-3 capitalized costs of €₂₀₁₅13.2 billion, which we translate into €₂₀₂₃15.5 billion; one view would be to even translate this, from the perspective of the first full calendar year of generation, into approximately €₂₀₂₆17 billion.

To understand the magnitude of these overnight cost estimates (including inflation), this corresponds to some €₂₀₂₄50 billion for a pair of EPRs, or more than triple the funds from operations (FFO) of any European integrated utility but EDF. Note that the unit price could be higher, if not built in pairs, than the approach currently contemplated by France, the UK and Czech Republic. This is also about five times the largest offshore wind farm project in the Organisation for Economic Co-operation and Development (i.e., about 10 times the share retained by the anchor owner, which typically retains only a 50% stake), whereas the secondary market for new nuclear project equity is very narrow.

In our view, the key parameters to calculate costs included in the cost of funding are a) the real-term WACC (since inflation is already factored in the overnight costs) and b) the overall overrun duration over which already-spent amounts are carried on the developer’s balance sheet up to COD. We examine them in turn.

• While WACC may be known at FID if all the financing is ready, it is not known before that date; crucially, even shortly before the expected project finalization, COD may be pushed back significantly into the future. For the duration profile of the capex outlays, this is crucial because most spending may have occurred that needs to be carried by the developer’s balance sheet up to COD years longer than expected, before cash inflows start streaming in.
• Assigning a WACC is inherently complex, particularly for projects like NNBs and EPRs. Even when sophisticated risk-mitigation strategies are applied, these projects are fairly unique and risky in terms of project-management challenges, given their reliance on a single, or at maximum, two, generation units (versus hundreds of wind or solar assets typically involved in those energy projects).

• The WACC should reflect project risks, which are notably significant for projects that, on their own, contributed substantially to bankruptcies or near-bankruptcies, like those of Toshiba and Areva, or key developers, suppliers or contractors. EDF’s €12.9 billion impairment of HPC assets and the EDF Energy goodwill also suggests that, despite the Contract for Difference (CfD) protection, on its own, the project company’s credit quality would be severely challenged. 

  •  Unfortunately, WACC typically is not even referenced publicly: since financing large nuclear projects is challenging, most developers carry the investments on their balance sheet and do not necessarily disclose the WACC they may use, even for depreciation accounting tests. Attributing the developer’s WACC in general to the project in particular is hard to justify and could significantly understate the WACC, even more so if, like EDF, the developer is a government-related entity (GRE).

LCOEs are the highest for nuclear, highlighting its lack of cost competitiveness in construction in Europe. While the LCOE metric does not capture all benefits of the nuclear technology (it represents firm decarbonized power with relatively lower grid connections compared to renewable sources), it is still a helpful tool to compare with other technologies.

LCOE estimates vary tremendously according to assumptions and, possibly, according to the particular estimator’s viewpoint, such as a government, the International Energy Agency (IEA) or anti-nuclear NGOs, for example. Effectively, whether the reactor’s economic life is set at 40 versus 60 or more years, a WACC at 6% or 10%, or load at 90% versus 70%, heavily impacts LCOE outcomes. We also believe LCOE is best suited for governments to take decisions to build or not build, which utilities — particularly GREs close to the government — then typically would have little room to reject. Thus, below we focus on the “near-term” (construction period plus early years post-COD) cash-flow implications of an unsubsidized reactor.

In our view, no funding on NNBs during the construction phase can be structured absent taxpayer or consumer support. This support can take the following forms:

• A subsidized state loan during construction and a CfD support during operations, as envisaged by the Czech Republic for Dukovany 5.
• State ownership, even when the state was previously absent from nuclear (e.g., SZC, where the UK government is and would remain the largest shareholder), combined with Regulated Asset Base (RAB) support starting from Day 1 of the construction phase. The objective is to reduce WACC and to share cost overrun risks.
• State-owned bank funding and intergovernmental loans, such as for Paks II in Hungary.

Let’s look at two very different support schemes: i) the UK’s scheme combines taxpayer and consumer supports; ii) the Czech Republic’s scheme principally rests on taxpayer support as it seeks to keep a lid on end-consumer prices. What they have in common is an aim to support cost of capital, funding and liquidity from the start of construction. We do not discuss OLK-3's Mankala risk-sharing model given its uniqueness to Finland.

The UK aims to support the construction of its new SZC nuclear plant through a RAB-based model applied ex-ante from the first day of construction. This approach allows for risk sharing for projects that are complex, time sensitive and subject to cost overruns. The Czech Republic is considering an interest-free state loan during construction, which would cover nearly all costs and cap CEZ’s contingent equity exposure to under €2 billion; once operations begin, all electricity produced would be sold to the state under a PPA that includes 40-year CfD protection for the generator.

What are the advantages of each model?

• From the developer’s credit perspective, the UK’s “RAB in construction” model is more supportive relative to the Czech Republic’s model in that the project produces cash flow from Day 1.
• The “RAB in construction” model is less supportive in that it still requires raising debt on the market during construction, versus relying on a typically strong source of financing, i.e., the central government, as the Czech model would.
• Given the relatively modest equity layer, the UK and Czech schemes offload most of the cost of capital during construction to consumers and taxpayers, respectively.

What are their limitations?

• The RAB-based model, which ultimately transfers the risks to UK consumers, is not easily replicable under EC State Aide laws. The EC’s overarching principle is to remain agnostic on technology choice in a country’s energy mix to avoid advantaging one technology over the others. What's more, the EU has clearly privileged CfDs in the operational phase for all technologies, including renewables; distinguishing nuclear with a different remuneration scheme could pose challenges.
• Affordability remains a constraint for RAB-based models as long as NNBs face risks of the cost base being inflated during the construction phase.
• CfDs do not protect operators during the construction phase and do not constitute a protection for cost-effective and timely delivery of the NNB project.

We believe new nuclear projects typically stretch corporate balance sheets for European utilities, absent considerable state or consumer support for construction, access to financing, long-term arrangements to support revenue stability, and end-of-life-cycle liabilities. The capex size of a typical new nuclear project is very large compared to a typical utility's balance sheet.

Construction risks weigh on the business and financial profiles of developers

The most prominent example is EDF, which took a hit on its balance sheet by bearing construction costs of two major new builds at the same time. Back in 2016, EDF contracted the FID on two new reactors at HPC, taking 75% ownership along with its Chinese partner CGN, and bearing thus the proportionate share of construction costs, while still bearing the construction of its nuclear new build, Flamanville. We downgraded at the same time the rating to A- and stand-alone to bbb- to reflect i) increased execution and contingency risks for the group, and ii) large additional investments adding to the large negative cash flows. The large cost overruns and time delays on both projects largely contributed to further deterioration of the group’s credit quality from 2016 until 2022.

TVO’s rating trajectory is another example of how construction risks and costs for a new nuclear plant have increased the utility’s operational and financial risks. The OL3 EPR was delayed nearly 15 years and faced substantial costs increases since inception, resulting in TVO being downgraded to BB during the OL3 construction phase.

CEZ’s current ratings assume near-full insulation from construction risks on new reactors. No FID has been reached yet, but CEZ is contemplating building two reactors (and possibly up to four), whose funding mechanisms have been approved for state aid by the European Commission.

Some mitigation can nevertheless come from credit-supportive channels to bridge the construction costs burden during the operation phase  

There are various approaches to “recycle” a sufficient portion of the funding back to protect the developer’s credit quality and incentivize one to actually build the project. Recycling the funding, so as to find a developer in the first place, can take various forms, as examined in Section 3. What already emerges, from the above cost analysis, is that at least two support channels are best considered:

• Revenue support
• WACC mitigation

Revenue support is the most visible channel from a media/society viewpoint, as the focus on HPC’s CfD — likely exceeding €150/MWh upon COD — illustrates. Yet, per the sensitivity analysis above on real-term WACC and duration of capex carry, WACC mitigation is equally relevant, given both the predominance of capex in LCOE and the length of project carry on the developer’s balance sheet, before the reactor produces cash.

NNBs in operation can sustain credit quality depending on the remuneration model

Credit risks hinge on how remuneration schemes address merchant price exposure; however, we believe the risks related to availability and load factor are reduced compared to older reactors.  

• Once in operation, NNBs produce massive decarbonized energy, generating free cash flows for decades. Nuclear operators can profit from high carbon prices and high power prices (for example, EDF in 2023). But many utilities in Western Europe cannot fully capture these benefits. Outside operational issues from aging fleets, this is due to taxes (for example, clawback measures in Spain), unfavorable regulations (for example, unchanged French ARENH prices [ARENH = Regulated Access to Incumbent Nuclear Electricity] at €42/MWh since 2012), risks of unpredictable load factors (for example, if renewables have priority access to the grid and nuclear utilization falls, or due to massive unplanned outages), or hedges in place. 

• Asset retirement obligations constrain operators’ balance sheets, not kicking in formally before the commercialization phase or COD (but if a project were abandoned, that would carry dismantling costs too). 

An overview of rated utility companies with material nuclear exposure is provided in the table below:

Massive new build projects have gained momentum in some European countries, but financing them remains fraught with challenges. To sustain the development of these key decarbonization projects, countries are looking at innovative funding mechanisms to mitigate the heavy cost burden on operators. Construction risks will remain key concerns for the ratings trajectory of the involved utilities, and we will monitor the implementation of credit-supportive funding solutions that often require strong state involvement.