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By Claire Mauduit-Le Clercq and Emmanuel Dubois-Pelerin


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.

Highlights

From the current limited nuclear power construction activity, with about 3 GW in progress, Europe seems ready to accelerate again, but only in countries already operating nuclear reactors. This comes amid increased geopolitical tensions, energy security concerns, aging existing nuclear fleet and increased need for firm and low-carbon power to deliver on electrification and decarbonization ambitions.

We estimate that the total cost for new build could be up to €15 million/MW, well above most other clean energy sources. This estimation notably considers overnight costs, cost of capital, and time — all of which can result in significant variations and add to unpredictability.

We believe the economics of the projects and the credit quality of the involved utilities will therefore rely on the efficiency and credibility of the frameworks that will govern these assets. Economic viability depends on dedicated remuneration schemes, risk-sharing mechanisms and government support. The need for robust frameworks is exacerbated by the substantial upfront investment funding needs of each project and a negative track record of significant time and cost overruns we observed on recent projects.

In any case, any nuclear new build will take years to become operational and connect to the grid, creating ongoing tensions on projected economics and future power market dynamics. Managing these will be key to attract investors while protecting consumers.

In this report, we explore selected European countries’ ambitions for nuclear new build (NNB), we detail our estimation of total adjusted cost for new European nuclear capacities, and we provide our credit views on the pros and cons for support mechanisms envisaged to attract funding for these new projects.

Why does it matter?

As a firm, low-carbon energy source, nuclear is increasingly seen as a key part of the solution to meet European decarbonization ambitions and its energy sovereignty. Yet after decades in limbo, notably since the Fukushima accident in 2011, the relaunch of the European nuclear industry comes at a cost, and governments and utilities both need to define frameworks that will convince investors of the risk reward.

What do we think, and why?

European NNB is costly, risky and will require substantial funding. When those reactors are built, however, they will provide firm low-carbon power generation at much lower grid costs than wind and solar. To mitigate the construction risks and attract capital, new frameworks need to be implemented to share the burden and the risks. Governments will play a key role in supporting and delivering on these projects.

1. Since 2022, the role of nuclear has benefited from more tailwinds for countries currently operating reactors

Reluctance to nuclear power dissipated in parts of Western Europe due to the 2022 energy crisis, prompting an emergence of new candidates for nuclear technology. The gas and energy crisis exacerbated by the Russia-Ukraine war has put nuclear power back in the spotlight in terms of energy security in Europe, which is less dependent on a single risky supplier of the raw material (uranium) than it was on gas before 2022.

Amidst geopolitical tension, ensuring physical delivery of power to avoid blackouts on top of securing long-term sovereign energy supply have become key priorities for Western and Eastern European states. The extensive 2022 outages (+47% year over year from 2021) of French electricity provider EDF (BBB/Positive/A-2), which sparked tremendous supply tightness in the continental platform, also highlighted the crucial role of nuclear power sources to provide firm power, a role that intermittent renewables cannot perform, especially given weak battery deployment. At the same time, the problems facing the French nuclear fleet exposed the risk of relying on a single, aging technology that will require significant investments in order to maintain its output over the next decade.

The rationale for nuclear power needs to be looked at from a whole-system point of view and resides on the following features: (a) it is the only proven at scale, expandable low-carbon source of firm power (since reservoir hydro capacity is nature-constrained); (b) it would limit the increase in grid capital expenditure (capex) through Europe’s energy transition; and (c) the security of energy supply would increase by maintaining a diversified energy mix that includes nuclear.

The European Parliament also approved the classification of nuclear as “green” under the EU Taxonomy for sustainable activities, making nuclear power an eligible option to bridge Europe’s decarbonization trajectory. This is key, as this contributes to alleviating pressure on funding (see the discussion Nuclear as a bridge to 2050 in the European Union in this report for more details).

New build projects are key for Europe's net-zero path to maintain a share of decarbonized firm power in the mix and to complement the growing share of renewables. New builds are even more crucial in countries operating often decades-old nuclear plants, to merely stabilize that component of their electricity supply. New builds are even more necessary in a context of demand growth driven by the electrification megatrend; this holds true especially if renewable deployment appears slower than projected due to lengthy permitting and public opposition (to wind, largely).

Nuclear is preparing a comeback, but only in certain countries

Many countries have shut all capacity or are only vaguely considering new nuclear. However, 5 GW of pressurized water reactor design capacity in the UK and France over 2024–2030 and 0.5 GW in Slovakia are under construction (one of Slovakia’s reactors, MO3, has been in operation since late 2023).

There are numerous projects with a commercial operations date (COD) beyond 2030, but none has reached final investment decision (FID) yet, suggesting commissionings from 2035 rather than before that date:

  • EDF probably has the firmest plans for new capacity, with six to 14 new domestic European Pressurized Reactors (EPRs) (10 GW-24 GW) scheduled for commissioning from the latter part of the 2030s. However, we are not aware of any public recent costing and financing plans.
  • The Czech Republic recently increased its planned number of reactors from one to four and has chosen Korean company KHNP (AA/Stable) as its key engineering, procurement and construction (EPC) contractor to develop the first two.
  • Poland has plans for up to six new reactors (the first of which would be built by Westinghouse) and small modular reactors (SMRs), with significant state loan funding.

At a less mature stage stand the Netherlands and Sweden. In Sweden, the government in place since 2022 is more pro-nuclear and has started to update laws (for example, on where nuclear plants can be built) to facilitate new builds. No FID has been taken yet given unclear costing and financing. Both SMRs and traditional plants are considered, but not for a COD before 2035, in our view.

Deep rifts on nuclear policies nonetheless remain between various European countries. The nuclear exit in Germany by April 2023 further weakened nuclear generation in Europe in the coming years, as could the effective implementation of closures in Spain. We see no new “converted” countries either, except maybe for Italy (SMRs from 2030, still speculative at this stage).

SMRs are not yet the next big thing as an alternative or complement to large-scale nuclear

SMRs are defined as small nuclear reactors with a typical unit size of 300 megawatts-electric (MWe), essentially small nuclear power plants with simplified reactor design and more flexibility to meet demand. Because they require a lower capital investment and are less complex projects than large-scale nuclear, they are considered an attractive decarbonized power source in the future energy mix of a growing number of European countries, including France, Sweden, Italy, Czech Republic, Romania, the Baltics and Poland. Demand is growing, but the technology is not yet mature nor developed on a large scale. Encouragingly, on July 30, 2023, Rolls-Royce SMR and the UK’s Office for Nuclear Regulation (ONR) said in separate statements that Rolls-Royce SMR’s 470-MW pressurized water reactor has entered the third and final stage of the UK’s generic design assessment process. However, the July 2024 revision in design announced by EDF subsidiary Nuward, the largest current European SMR prototype, emphasizes the hurdles of a technology that is still in its basic/detailed design stage. As of the writing of this report, four SMRs are in operation globally (only in Russia and China), while four are under construction and none of them are in Europe. However, the pace of the technological development in North America accelerated in 2023: early construction started on the Terrapower Natrium plant in Wyoming, and works in Darlington, Ontario (GE technology) are due to begin in early 2025. In addition, large energy users are increasingly considering SMRs as a source of baseload power and heat, with tech companies accelerating their involvement.

Data centers’ potential boost in power demand is fueling wider interests for nuclear

The rise of data centers and of their power demand represents an additional call of potentially 10-15 terawatt hours per annum (TWhpa) more in Europe. Optimally for tech companies, this electricity should be firm and decarbonized, i.e., reservoir hydro or nuclear, which, outside Scandinavia, means nuclear. In the US, North American nuclear power plant operator Constellation Energy signed a 20-year power purchase agreement (PPA) in September 2024 to power Microsoft data centers on Three Mile Island Unit 1, a reactor retired since 2019. Additional developments followed in mid-October: Google announced a PPA with SMR manufacturer Kairos, and Amazon announced deals with Dominion Energy and Energy Northwest to explore the development of several nuclear SMRs, as well as an investment in X-Energy, an SMR manufacturer. Challenges remain, including the timing mismatch between near-term additional demand from data centers and long NNB construction times, risk-sharing on operations and maintenance costs, connection of data centers directly or indirectly to the grid, etc.

Nuclear is a cornerstone of the energy transition in parts of Western Europe and Eastern Europe, not in Southern Europe

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.  

Nuclear as a bridge to 2050 in the European Union

The EU Taxonomy Delegated Act issued in December 2021 allows the following nuclear activities to be eligible for support:

  1. Investments in new Generation III+ projects approved for construction until 2045
  2. Research and development for advanced technologies promoting safety and minimal waste
  3. Modifications to extend the lifetimes of existing nuclear installations (must be approved by 2040)
  • This is relevant for the access to funding of actual or potential builders of nuclear capacity, such as EDF in France, SE in Slovakia, CEZ in the Czech Republic and potentially operators in Sweden and the Netherlands.
  • In contrast to new Taxonomy-compatible gas-fired capacity, we expect nuclear new builds to lean significantly on public support, given their size and construction risks involved.

RePowerEU gives nuclear a key role in ensuring energy sovereignty

The European Commission (EC) recognizes in its 2022 approved REPowerEU plan the key role of nuclear in the European Union to ensure energy supply security. The EC also highlights in the same plan the importance of coordinated action to reduce dependence on Russian nuclear material and fuel cycle services. RePowerEU envisages that nuclear plants could be used to produce hydrogen and that in the longer term, the development of innovative and flexible nuclear reactors such as SMRs should be fostered.

The Net-Zero Industry Act (NZIA), approved by the European Parliament in November 2023, emphasizes SMRs for new nuclear. The NZIA sets a target for Europe to produce 40% of its annual deployment needs in net-zero technologies by 2030 and to capture 25% of the global market value for these technologies. Included in the 10 proposed technologies were "advanced technologies to produce energy from nuclear processes with minimal waste from the fuel cycle, small modular reactors, and related best-in-class fuels."

NNB in Europe is crucial due to aging fleets

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. 

2. The level and unpredictability of costs of new nuclear builds are a major obstacle to the renaissance

In our costing exercise below, we focus on new large-scale reactors. Given the need to use a local supply chain for a substantial part of construction activities, much of the analysis could well apply to non-European constructors of Europe-located large reactors, e.g., Westinghouse’s projects in Poland (but not to SMRs, given the less mature stage of development, nor Hungary’s projects using Russian technology) and — at lower levels of construction costs — to the Korean-technology-based projects in the Czech Republic.

In this report, we do not focus on lifetime extensions, which are indisputably cheaper than a new build, whose levelized cost of electricity (LCOE), even with mild assumptions, is probably at least three to four times French energy regulator CRE’s estimate of €30-€40 per MWh for EDF’s 12-year, approximately €68 billion “Grand Carénage” investment program. Reciprocally, one could embed in a new EPR LCOE the optional value of a future extension beyond the assumed lifetime — but most projects already target 60 years from the start (versus typically 40 years in the past), so that optional value beyond 60 years is very uncertain and at any rate stands so many years away (around 2090 for new construction starting now) that its net present value is relatively modest. We see lifetime extensions as supporting the related utilities’ credit quality only for existing reactors.

An interesting new chapter could be the recommissioning of recently decommissioned reactors, as is being considered for two in the US. This idea could be of interest in Belgium, as noted recently by system operator Elia in its 2036–2050 study, or in Spain as recently proposed for discussion by nuclear operators. In Germany, this would require such a significant policy change that we see recommissionings as remote.

“Overnight costs” likely approach or exceed €10 million/MW for new EPRs built in Europe

We look at NNB costs in three steps:

(i)    Start from the schedule of cumulative costs in nominal amounts, with particular attention to ancillary and/or expensed costs.

(ii)    Bring them all to a common currency value (e.g., British pound (£) at 2024 value) by indexing the various years’ flows to inflation (e.g., £1 cashed out in 2015 represents £1.3 in 2024: £20151 =  £20241.3).

(iii)    Add real weighted average cost of capital (WACC) costs, since absent project cash generation during construction, the entire amount needs to be financed.

The following flowchart illustrates the steps for determining NNB costs (using euro as the currency):

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 date8 million/MW for Finnish OLK-3 (as heavy spending had taken place a decade before the 2023 commissioning) and €COD date10 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 date11 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.

The all-in “WACC-loaded cost” likely exceeds €15 million/MW for most NNBs; what’s more, it is highly sensitive to WACC assumptions and commissioning delays

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).

The WACC levels are very relevant as we evaluate the impact on project economics and the credit risk on the developer of any cost overrun and/or delay (€COD date denotes euros as of the commissioning date, i.e., all flows are adjusted for inflation to be comparable in monies of the commissioning year):

  • For illustration, applying a 3% real-term WACC and a seven-year average scheduled carry (i.e., for a “normally executed” project) to a €COD date10 million/MW “overnight cost” corresponds to an all-in cost (WACC-loaded costs, still ex-ARO) of €all-in12.3 million/MW. In the first year of full generation, assuming 2% inflation and a 90% load factor, this corresponds to a financial burden of €78/MWh. ([5% of 90% of 8.78 Twh at €12.3 billion/GW capital invested] overnight.)
  • Raising real-term WACC over seven years to 6% on the same €10 million/MW “overnight cost” raises WACC-loaded costs to €all-in15 million/MW (a financial burden of €152/MWh).
  • Applying an additional five-year delay stress to the planned schedule raises WACC-loaded costs to €all-in20 million/MW (a financial burden of €209/MWh).

The lack of cost competitiveness for nuclear technology construction in Europe is obvious versus other technologies and other regions

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.

3. Government or customer (RAB) support is vital for funding of construction and may help ROI

All current funding mechanisms envisaged for NNBs include strong taxpayer or consumer support

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.

The UK and Czech funding schemes for nuclear new builds suggest credit-supportive solutions exist

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.

Focus on state support in Czech Republic

The Czech state plans to support the construction and operation of the new 1.2-GW capacity power plant in Dukovany with final COD in 2038. The state plans to grant direct price support, from COD, in the form of a PPA with a state-owned Special Purpose Vehicle (SPV), to ensure stable return on equity for the plant for 40 years (down from the initial 60 years Czech authorities requested for EU approval). The beneficiary of the measure is EDU II, a fully owned subsidiary of CEZ Group (the only nuclear plant operator in the Czech Republic). During construction, EDU II will benefit from a subsidized state loan and a protection mechanism against unforeseen events or policy changes impeding the project’s realization. During operations, this subsidy will take the form of a floating- to-fixed price swap between the government and the SPV, whose strike and reference prices are not known yet but are intended to protect the return on equity. 

The European Commission provided its approval on principle of funding for construction of one reactor, on April 30, 2024 (see “Commission approves State aid to support construction of nuclear power plant in Czechia”).  

The contrast between HPC and SZC in the UK

For the in-progress Hinkley Point C (HPC) new build, the UK government has committed to a long-term CfD with a guaranteed price of around £130/MWh in today’s money according to the UK’s CfD Register (being CPI indexed, it may therefore exceed €170/MWh when commissioned) over a maximum 35-year period when reactors are commissioned. HPC construction risks are borne by EDF’s balance sheet pro rata to its fluctuating ownership throughout the construction (now bearing 100% of the construction costs).

The UK government has elaborated a very different funding plan for the separate Sizewell C (SZC) project, whose FID/financial close is still to come in 2025
(after some delays). To enhance the financeability and investability of its nuclear plant to be constructed, SZC will benefit from an extensive regulated asset base framework, to support funding during construction with regulated revenues kicking in on Day 1, as well as significant risk-transfer mechanisms. This Ex-Ante RAB Model (below) was validated by the UK Nuclear Energy Act (2022), which published the preliminary or near-final Licence Conditions in April 2024, after consultation with main stakeholders including EA, ONR, SZC, Citizens Advice, Ofgem and EDF SA. Further liquidity and high- risk, low-probability support comes directly from the UK government through a comprehensive Government Support Package. 

Nuclear Ex-Ante RAB Model highlights: 

  • It is in line with other UK RAB models to cover for unique long time-lead and sizeable-costs projects, but adapted to nuclear.
  • It offers predictable revenue derived from a WACC return on RAB adjusted to reflect total expenditure, which allows the licensee to receive fast money rather than the expenditure being capitalized to the RAB and compensated over time, but with a predefined cap that safeguards escalation of costs (the financing cap).
  • Other revenue building blocks are debt costs adjustment, pass-through costs (such as regulatory fees and electricity industry fees), incentives and penalties (with respect to capital cost, outages and other operational performance concerns), reserves and decommissioning fund provisions, ensuring the plant can meet its targets through the incentives and penalties within the model.
  • Post construction, nuclear-allowed revenues (as per the regulated formula) will also include decommissioning payments and operational incentives.

We recap the supportive credit features embedded in SZC’s contemplated regulation and financing package as follows:

  • A predictable stream of RAB revenue starts from the first day of construction
  • Revenue support in case of operational outages with a limit fixed at the financing cap (we view this as the maximum protection level against costs overruns)
  • Committed funding to cover construction up to a predetermined level of capex (covering partly some capex overspend, in line with the financing cap)

4. Nuclear new build exposures typically constrain ratings credit quality, absent substantial burden sharing (partners, state support, RAB, etc.)

Overall, exposure to new builds tends to constrain ratings

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:

Conclusion

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. 

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Contributors

Sylvain Cognet-Dauphin

S&P Global Commodity Insights

Sylvain Cognet-Dauphin

Executive Director, Climate and Sustainability


Pierre Georges

S&P Global Ratings

Pierre Georges

Managing Director


Livia Vilela

S&P Global Ratings

Livia Vilela

Director


Editorial, Design & Publishing

Cat VanVliet 
Associate Director,
Data Visualization 

Editorial, Design & Publishing

Angela Long
Lead Editor