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Nuclear In Europe: Lessons Learned And Ways Ahead

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Nuclear In Europe: Lessons Learned And Ways Ahead

(Editor's Note: This article, originally published on Dec. 16, 2021, was republished on Jan. 14, 2022, to correct table 3 for the outlook on and nuclear capacity of Vattenfall. A corrected version follows.)

After decades of opposition by governments and public unease after the Fukushima disaster in 2011, Europe may be changing its mind about nuclear energy. The U.K. government considers nuclear as part of its decarbonization strategy, and the technology could be included in the European green finance taxonomy, a key milestone to attract private capital. Europe's energy crisis casts new light on the role of nuclear power and calls for considering all types of low-carbon energy. As decarbonization is a clear priority for Europe, nuclear energy is generally recognized as a proven technology that can contribute to decarbonization as well as stability and affordability of energy supply, which its use in the U.S., China, and Russia shows.

Recently, President Emmanuel Macron of France announced the resumption of new nuclear builds, for the first time in 40 years, to address the country's decarbonization targets. Although no details about the numbers of reactors or the technology of choice have been disclosed, this represents an emblematic shift in nuclear energy prospects in France. In parallel, the U.K. government introduced legislation establishing a funding scheme based on regulated asset base (RAB) for new nuclear projects, and made public its decision to invest up to £1.7 billion to enable a large-scale nuclear project.

S&P Global Ratings believes that a return to nuclear power in Europe will not be quick or easy, as it would rely on difficult political decisions and require large financial outlays, public investment, and management of complex technical advances. Also, some European countries have already decided to phase out nuclear and are unlikely to change their stance, notably Germany. We believe that a nuclear renaissance is hardly possible without state support for access to funding, construction, operations, and managing end-of-life liabilities--which can come in varying shapes or forms.

image

Europe's nuclear industry is struggling with an aging fleet and regulation

The nuclear industry in Europe has been struggling and is set to decline, due to mandatory phaseouts of nuclear capacity and the age of many plants. According to S&P Global Platts Analytics, nuclear generation in Western and Eastern Europe (the latter includes Turkey) may decline 7% by 2030 and 17% by 2040. The decline for Western Europe is even more pronounced, at 11% in 2030 and 26% in 2040.

Chart 1

image

The Fukushima disaster highlighted technical risks and questioned the role of nuclear in Europe, leading to significant cost inflation related to more stringent security and safety requirements for nuclear sites, which required large investments by operators to meet them to maintain their operating licenses. Fukushima also led to Germany's drastic decision to completely exit nuclear by 2023. Other European countries, such as Belgium, Switzerland, and Spain, have decided to exit from nuclear and programmed the closure of their nuclear power units, by 2025 for Belgium and 2036 for Spain. Other countries, such as France and the U.K., have opted until now for a status quo approach of relying on their aging fleet and thus allowing the gradual decline of their nuclear production. For instance, France, which operates Europe's largest nuclear fleet of 63 gigawatts (including the commissioning of FLA-3) currently plans for the closure of 12 nuclear reactors (as they reach the end of their lifetime). That translates into a mechanic reduction in the share of nuclear power in the country to about 50% by 2035 from over 70% today.

Most European nuclear reactors were built in 1980s and early 1990s. Typically, their useful lives were initially set at 40 years and in some cases subsequently extended through additional investments and new licenses. As many European nuclear plants come closer to the end of their useful lives, the question is, how to fill the void left by nuclear retirements without challenging stability of electricity supply or detracting from decarbonization goals. Given long lead times for nuclear approvals and construction, this calls for decisions today about whether to invest in new nuclear units, extend the life of existing nuclear plants, or replace nuclear with other types of power generation--especially renewable energy or temporary gas solutions. Although the construction of new nuclear plants in the past decade have been very expensive in Western Europe, life extension costs could still be cost-competitive. This is notably the case, considering the complete costs for the electricity system of integrating renewable sources, which include significant costs for ensuring system flexibility and massive grid adaption costs.

None of these decisions is straightforward or without limitations. What's more, they will be political by nature, so consider many factors, such as economics, social acceptance, affordability, land use planning, and consumption patterns.

Chart 2

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How to fill the void left by retiring nuclear?

With the large mandatory or "natural" nuclear retirements looming in Europe, the question is how to fill the void and compensate for this source of baseload electricity capacity. While opting for additional nuclear capacity will be difficult, the alternatives aren't exactly easy street.

One option is renewables. Wind and solar are the most favored technologies under the European Green Deal and draft Green Taxonomy, which supports their access to funding and often attractive tariffs. Still, wind and solar conditions vary significantly across European countries. Renewable generation is intermittent and unpredictable, and Europe currently doesn't have sufficient power storage capacity in place to compensate for it. The need for replacement of these large retirements of stable low-carbon nuclear in coming years add to the already ambitious investments needed to ramp up renewable generation and to develop electricity grids to integrate it. As stable nuclear or coal baseload capacity is set to close before sufficient power storage is in place or other dispatchable power capacity is built (such as gas with carbon capture and storage or hydrogen-burning plants), higher reliance on naturally intermittent renewables may exacerbate the volatility of electricity markets, challenge security of supply, and create additional risks for system stability.

Another option is gas. Gas is sufficiently flexible to back up intermittent renewables before more permanent energy storage solutions are in place. For example, Belgium plans to build new combined cycle gas turbines to replace its 6 GW nuclear retirements. Burning gas results in lower carbon emissions compared to burning coal. Still, unless gas is complemented with carbon capture and storage, switching from nuclear to gas increases the carbon footprint and carries the risk of locking into a fossil fuel, which pulls Europe further away from its net-zero targets. Also, such a shift would increase the region's exposure to highly volatile global gas markets and geopolitical risks.

Hurdles to nuclear: technical or political?

Nuclear faces strong political, social, and regulatory pressures because of concerns about the risk of low probability but high-impact accidents as well as waste treatment and storage solution. They undermine social acceptance of nuclear technology and its image in the eyes of investors. What's more, every incremental increase in safety requirements comes at an ever-increasing additional cost, boosts capital spending requirements, and affects operating profitability. Also, geopolitical considerations about dependency on Russian or Chinese nuclear technology may affect decision making, as after many years without new reactor commissioning, Europe lacks sufficiently deep local supply chain, technical, and project management skills.

Although nuclear is not included in the current draft of the European green taxonomy, but it wasn't fully excluded either. Although nuclear is a low-carbon technology, political sensitivity about the "do no significant harm" principle remains high. EU's Technical Expert Group on Sustainable Finance could not make a conclusion about the safety and security of nuclear technology. The EU therefore asked the Joint Research Center (JRC) to perform a detailed scientific study that we understand will serve as a basis for decision on the EU taxonomy. Subsequently in 2021, the JRC issued a detailed technical report that did not reveal any science-based evidence that nuclear energy does more harm to human health or to the environment than other of the electricity production technologies included in the taxonomy. The main arguments of the report are:

  • The EU's existing regulatory framework already provides for appropriate measures to prevent potential harm to human health and environment, or mitigate it, using existing technology at reasonable costs. For nuclear energy, its impact on water consumption and thermal pollution, as well as safety of other life cycle stages, can and should be appropriately addressed through site selection, facility design, and operation--in line with the existing framework.
  • The total life cycle impact of nuclear power generation on human health, both radiological and non-radiological, is comparable to offshore wind. In particular, nuclear's average fatality rate is comparable to the rate for renewables and materially lower than for fossil fuels. However, the maximum fatality rates for nuclear are somewhat higher, comparable to non-OECD hydropower. Severe accidents involving core meltdown are extremely rare; there have been only three in the industry's history: Chernobyl (1985), Three Mile Island (1979), and Fukushima (2011). The reasons were different, and were subsequently addressed via regulatory tightening and technical improvements.
  • The JRC report also mentions that although the scientific consensus about nuclear waste disposal is that storage in deep geological formations is sufficiently safe, this technology has not been widely implemented in practice.

Given the European populace's natural loss aversion, low tolerance for catastrophic risks, as well as negative social acceptance, it remains to be seen whether the European Commission will consider these technical findings sufficient to include nuclear in the green taxonomy, or whether additional research would be required. In particular, the report admits that severe accidents, however rare, cannot be ruled out with 100% certainty, and the risk of human error cannot be ignored. Also, one of the crucial points of the nuclear controversy is waste storage, and deep geological waste storage has no operational track record.

An EU ruling on the green taxonomy, expected for December 2021, is crucial for access to both private and public funding for nuclear power projects. The taxonomy is designed to provide a comprehensive and uniform classification of green projects. The projects compliant with the taxonomy, such as renewables, can benefit from massive EU grants and wider access to private investment. Because private investors will be obliged to report whether their portfolios comply with the green goals, they will have a strong incentive to avoid significant exposures to technologies that are not part of the taxonomy. If the EU cannot come to a consensus about nuclear in the green taxonomy, national policies would be crucial for the industry. New nuclear projects are very capital intensive and depend on access to sufficient funding. For Eastern European countries with high dependency on coal and a less developed local investor base, the availability of EU financing may be a significant factor in how they decide to structure their decarbonization policies.

Lack of expertise and supply chain woes

The European nuclear industry has been struggling over the past decades to maintain a sufficiently deep local supply chain, as well as local technical and project management expertise. This contrasts with China or Russia where vertically integrated local nuclear players have been quite successful. For Europe, overreliance on foreign contractors for the nuclear industry may not be politically acceptable.

With very limited new nuclear builds, lower order volumes in the past decades, uncertainties about growth prospects, and high and unharmonized safety standards across countries, high reputational risks, and high perceived financial risks, the European nuclear market has not been attractive enough for suppliers (JRC report, 2020). Meanwhile, the cost is high of maintaining the skill set up to nuclear standards and the supply chain is long and diverse--ranging from original equipment manufacturers and system integrators to subcomponents and raw materials. In Europe, there has been a lack of investment in supply chain initiatives, which contrasts with efforts in the U.S., China, and Russia. The European nuclear industry has been struggling to attract new suppliers and maintain existing ones and from the need to adapt to standards and regulations for new technologies. Also, the European nuclear industry has become much less attractive for young professionals than in past decades, and new employees do not have a practical experience in new builds.

The scarcity of local suppliers along this whole value chain as well as the shortage of industry expertise could jeopardize the execution and raise the cost of complex new nuclear build construction and weaken the performance of existing nuclear operators in Europe.

Is nuclear economically attractive?

Nuclear power in Europe is suffering from relatively high costs compared to other fuels such as renewables. Still, in other regions nuclear can be cost-competitive, and direct cost comparisons can be misleading. Generally, for nuclear, the key part of levelized cost of energy (LCOE) is cost of capital. For gas-fired and coal-fired generation, LCOE is driven by highly uncertain future fuel costs and will increasingly reflect high carbon prices. The cost of capital and its availability vary depending on investors' perception of the risks in generation technology and access to grants and subsidies. We believe that despite the fundamental capital intensity of the nuclear, part of its cost disadvantage in Europe is policy driven, because renewables often have priority access to the grid to support capacity utilization, and nuclear mostly doesn't.

New nuclear in Europe faces mounting construction costs, as well as increasing regulatory, market, and technical uncertainties arising from the energy transition, unless offset by state support or long-term revenue arrangements. As new nuclear projects require massive upfront investments with a long lead time and typically 40-60 years in future operations, their economics are highly sensitive to construction costs (including to meet stringent safety regulations), applicable cost of capital, and the stability of the future long-term revenue stream. In addition, both new and existing nuclear in Europe face highly volatile electricity prices and potential pressures on future load factors to accommodate a growing share of renewables. Regulatory shifts and technology developments can further affect future costs and the length of the nuclear asset's life and therefore its net present value. And finally, end-of-life liabilities weigh on the companies' balance sheets.

Compared to nuclear, renewables have a much shorter payback, are scalable, enjoy strong regulatory support through favorable tariffs and vast access to funding, both government and private. A large increase in zero marginal cost renewables will make wholesale electricity prices lower and more volatile than in the past, which jeopardizes the stability of future revenue flows for existing and new nuclear plants. Market, technological, and regulatory uncertainties embedded in the energy transition increase the value of options embedded in smaller, flexible, and modular renewable solutions, and decrease the attractiveness of large and long-term commitments like nuclear.

Still, resorting to nuclear implies significant savings for the electricity system when focusing on the total investments required for the energy transition. This is because of significant flexibility needs, in form of bridge baseload needed to accompany renewables deployment, storage capacity, or network development. For example, in France, a report published by RTE on the future energy mix by 2050 highlights that there could be some economic rationale for new nuclear builds, combined with extending the lifetime of existing reactors, considering the overall cost of the electricity system, when compared to a no-nuclear scenario. Although any assessment of global decarbonization costs are highly uncertain, the IEA's net-zero scenario published in May 2021 estimated that in a scenario with a declining share of nuclear, global investment needs in power plants and related grid assets would increase about $2 trillion in 2021-2050.

New nuclear cost inflation

The cost of new nuclear builds in Europe is significantly higher than in other countries such as China or Russia. Essentially all projects in Europe, three new EPR builds, face delays and significant cost escalations.

  • OL-3 (1.6 GW capacity, Finland) is to start regular electricity production in 2022, more than 10 years after the initial delivery schedule of May 2009, due to a first-in-kind design, unforeseen regulatory hurdles, as well as project management issues. The brunt of the €9 billion in cost overruns, born by Areva S.A., brought total project costs to €12 billion.
  • FLA-3 is also in a late construction phase, with a total budget that has soared to about €12.4 billion, 3.8x above the original estimate. EDF announced at end-2020 that there were very high risks regarding both the schedule--fuel loading at end-2022--and completion costs, even though the review of the impact of the pandemic did not lead to any change in targets announced at end-2019.
  • HPC's two reactors (total capacity of 3.2 GW) are still in an early construction phase but have already incurred two major cost overruns, with the full budget now estimated at £22 billion-£23 billion, lowering the internal rate of return to about 7.7% , not high when risk-adjusted. EDF also delayed the start of electricity generation from unit 1 by six months to June 2026. In addition, EDF has flagged that there is a high risk it will delay the commissioning of units 1 and 2 by 15 and nine months, respectively, which would translate into additional costs of £0.7 billion in 2015 pounds sterling.

This contrasts with China and Russia, where serial newbuilds and local vertically integrated supply chains lead to significantly lower nuclear construction costs. For example, based on media reports, we expect the ongoing construction of two 1.2 GW nuclear units in Kursk, Russia, to cost about Russian ruble (RUB) 350 billion, or about $2,000 per kilowatt (€1,600/KW), comparable to the Leningrad 1.2 GW unit commissioned in March 2021. China's recent new nuclear builds include two advanced pressurized water reactors (under HPR1000 technology) of 1,180 MW by state-owned China General Nuclear Power Group, whose commissioning is expected in 2022 for a total investment of Chinese renminbi 38.9 billion (or about €3.9 billion), translating into a much lower cost (about €2,300/KW).

Table 1

Cost Estimates For Selected Nuclear Projects Around The World
Project / Country Capacity, megawatts (MW) Total cost Cost/kilowatt installed capacity (mil. €)
Olkiluoto 3 (OL 3) / Finland 1 EPR of 1,600 MW Budget €3.2 bil. to €11 bil. final cost 6,875
Flamanville 3 (FLA 3) / France 1 EPR of 1,650 MW Budget €3.3 bil. to current expectation of €12.4 bil. (in 2015 euros) 7,515
Paks II (units 5 and 6) / Hungary 2 units of 1,200 MW each Final cost of €12.5 bil. 5,208
Kursk II- 1, 2 / Russia 2 advanced PWR units of 1,255 MW each RUB350 bil. or about $4.7 bil. (our estimate based on media reports) 1,681
Hinkley Point C (HPC) / U.K. 2 EPR of 1,630 MW each Current expectation of £22 bil.-£23 bil. (with high risk of £0.7 bil. additional costs) 5,879
Fangchenggang, Guangxi Province / China 2 advanced PWR units Nos. 3 and 4, each 1,180 MW. Technology: HPR1000 (Chinese proprietary Gen III) Final cost RMB37.5 bil. or about €5.1 bil. 2,177
Note: Foreign exchange rates used: €1=$1.14; €1=Russian ruble (RUB) 82.95; 1€=7.3 Chinese renminbi (RMB). PWR--Pressurized water reactor; EPR--European pressurized reactor. Source: S&P Global Ratings.

We believe the difference in the cost for new nuclear likely results from tight post-Fukushima regulations, the lack of experience in recent nuclear new builds in Europe (both for the companies and for the regulators), a sufficiently deep vertically integrated supply chain, and lack of technical and project management skills in Western Europe. Having said that, we believe that nuclear life extensions can be cost competitive compared with other energy options.

The energy crisis could prompt European politicians to reconsider the role of nuclear

Skyrocketing gas and power prices in Europe and the political focus on energy independence raise the need for European countries to rethink the role of nuclear in light of its decarbonization targets and limits posed by renewable intermittency and by gas price volatility. The unprecedented scale of decarbonization calls for a technology-neutral approach to all forms of low-carbon energy and additional value ascribed to stability of energy supply.

Recently, the European Commission publicly expressed a change of tone toward nuclear. As discussions on taxonomy progressed, EC President Ursula von der Leyen commented that Europe needs nuclear as a stable energy source on top of more renewables, while gas would be needed during the transition. In October 2021, energy and economy ministers from 10 European member states called for including nuclear in the EU green taxonomy as a carbon-free, safe, and independent source of energy.

Nuclear is a proven technology that helps to ensure a stable and non-intermittent supply of low-carbon energy, allows time for renewables to mature, and reduces the cost of the energy transition. Once nuclear is built, it is independent from volatile commodity imports and related geopolitical issues.

For some Western European countries (see chart 3), nuclear is an important part of their electricity mix and a large source of baseload zero-carbon electricity.

Chart 3

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Some countries in Eastern Europe with high dependency on coal and limited renewables penetration and potential (for example, Poland, Czech Republic, Slovakia) increasingly view nuclear as the key tool to achieving Europe's decarbonization goals. For example, Poland, which currently has no nuclear plants in operation, aims to build 6-9 GW in new nuclear capacity to replace coal-fired generation (coal currently comprises 74% of Poland's electricity fuel mix), and is in intensive talks with French and U.S. providers for both traditional large and small modular reactors. Romania plans to construct small modular reactors (SMRs) to replace coal-fired capacity and reduce import dependency.

Outside of the EU but not too far geographically, Belarus has started its first 1.2 GW nuclear power plant in 2021 and plans to commission another one in 2021, with the aim to export electricity. Ukraine is considering replacements of its large and gradually aging nuclear fleet as well as deployment of SMRs. Turkey is building the 4.8 GW Akkuyu nuclear power station to replace coal in its energy mix, with the first of the four units scheduled to start in 2023; recently, the President of Turkey mentioned the possibility of building more nuclear plants in the future. In Russia, nuclear is included in the national green taxonomy approved by the government in September 2021, and the increase in the share of nuclear (likely to 25% from 20%) is one of the key tools in the new decarbonization strategy published in October 2021.

Nuclear exposures typically constrain ratings, absent state support

We believe that new nuclear projects typically stretch corporate balance sheets for European utilities, unless they enjoy state support for construction, access to financing, long-term arrangements to support revenue stability, and end-of-life-cycle liabilities. The size of a typical new nuclear project is very large compared to a typical utility's balance sheet. Even in countries where existing nuclear is profitable (for example, Czech Republic, Bulgaria, Hungary), replacement of existing units and building new nuclear can stretch balance sheets in the absence of state support.

For the Western European utilities we rate, nuclear operations often constrain credit quality absent state support. The aging asset base often affects operating performance through more frequent outages and higher maintenance costs. Although nuclear operators can gain from high carbon prices and high power prices (for example, Bulgaria, Hungary), many utilities in Western Europe cannot fully capture these benefits due to operational issues from aging fleets, taxes (for example, clawback measures in Spain), unfavorable regulations (for example, unchanged French ARENH prices 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 hedges in place.

Nuclear liabilities and final storage solutions remain a financial burden that can increase over time

Asset retirement obligations (AROs), including nuclear provisions for dismantling reactors and the management of nuclear fuel waste, net of dedicated assets, remain a financial burden for most nuclear operators. We treat these AROs as debt-like and consider we have little visibility about the potential for inflation of the underlying nuclear liabilities. These AROs typically constrain the financial flexibility of the emblematic French operator EDF (€10.6 billion out of total debt of €70 billion) and Engie S.A. for its Belgian operating fleet (about €10 billion out of debt of €60 billion). Still, in many countries, including some EU ones, the government shares or fully accepts the ARO burden. For example, in Hungary, the government is responsible for asset retirement liabilities, and the nuclear operator MVM makes prefixed annual contributions to the state ARO fund. in Russia, Atomic Energy Power Corp. is only responsible for AROs formed after 2011, and legacy liabilities are the government's responsibility.

Table 2

Asset Retirement Obligations (AROs) Related To Nuclear Power In Europe
(Mil. €) Assset retirement obligations (debt adjustment) Nuclear liabilities Dedicated assets Adjusted debt EBITDA in 2020 Funding
EDF 10,618 60,486 33,848 75,850 16,274 Company
Engie 11,427 14,677 3,929 42,791 8,903 Company
Atomic Energy Power Corp. 2,870 2,870 0 1,926 3,580 Company (since 2012)
E.ON 8,692 8,015 0 38,588 6,249 Company*
EnbW 1,860 4,098 2,238 12,034 2,935 Company
Vattenfall 44,358 8,941 4,102 11,602 4,163 Company§
Fortum 645 4,687 3,445 9,878 2,955 Company§
Uniper 630 2,916 2,495 2,538 1,922 Company*
Teollisuuden Voima Oyj  0 1,030 1,030 4,795 77 Company§
MVM Energy Private LLC 317 0 0 1,188 584 Government (through preset annual contributions from the company)
Note: €1=Swedish krona (SEK)10; Hungarian forint (HUF) 1=€0.0027. *Germany: AROs relate to plant decommissioning only. AROs related to the costs of intermediate and final nuclear waste storage have been transfered by German Act onto the Nuclear Waste Management Fund (KENFO, 2017) via €24.1 payment by 25 German nuclear operatrs into the KENFO. '§Sweden and Finland: Liability funded by companies annually into government managed fund (+ additional company guarantees in Sweden). Source: S&P Global Ratings.

In addition, intermediate storage capacity and as well as final storage of nuclear waste add further uncertainties to the calculation of end-cycle liabilities. In Sweden, the government extended the license for intermediate storage to mid-2021 but has not yet made any political decision about final repository storage. This is creating a high level of uncertainty for nuclear producers, and Vattenfall warned it will need to close down nuclear plants in 2024 and 2025 because existing intermediate storage facilities should reach full capacity by 2025. In addition, in Sweden, nuclear provisions will no longer be dated (at about 30 years) and represent thus an uncapped liability component of operators' off-balance-sheet commitment.

In France, while the principle of deep geological storage was adopted by French Law in 2006 as the final storage solution for nuclear waste, there are growing needs for additional intermediate storage. EDF's strategy for the nuclear fuel cycle, in compliance with the French Law, is to process spent fuel and recycle substances in the form of mixed oxide (MOX) fuel (In Orano's reprocessing plants, in The Hague) whenever possible. The 2016-2018 French National Plan for the Management of Radioactive Materials and Waste (PNGMDR) identified growing needs by 2030. EDF will not be in a position to file the construction permit application before late 2022 and currently plans to have the facility commissioned by 2034. Regarding burial in deep geological layers, France's Industrial Centre for Geological Disposal (CIGEO), developed by the French national radioactive waste management agency, ANDRA, is still in its conception phase with the first pilot industrial phase currently envisaged by 2030.

Government support is the key

We believe that most of European nuclear's economic woes can be mitigated if government policies are sufficiently supportive or if at least they treat nuclear similarly to other low-carbon technologies in terms of access to the grid, tariff stability, and stable technical requirements regarding safety and security.

To our knowledge, all large nuclear projects globally involve government-related entities (GREs) and often direct state support, and government loans or support from export-import banks. Government support can flow through the different phases of a nuclear project. During the construction stage, state support can reduce the cost of capital and provide visibility about funding until the plant is in operation and starts contributing to cash flow. In the commercial phase, state support can protect the stability of the nuclear plant's cash flow through stable "rules of the game." In addition to stable technical requirements, state support can come via stable offtake volumes at favorable prices (akin to renewable producers), capacity supply arrangements, or even a remuneration framework to ensure that capital and operational spending are covered and to allow for a fair return on investments. In the past 18 months, negotiations between the French state and the European Commission about a fixed price for nuclear generation highlight the importance of providing long-term visibility of cash flow. Finally, the state can share the financial burden of end-cycle obligations as is the case in Spain, Hungary, and Russia, alleviating private or state-owned operators from potential inflation of dismantling costs and long-term waste management.

Chart 4

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Although European rules about state aid constrain direct equity funding, many European nuclear operators are government-related entities and many benefit from indirect forms of state support. For example, Hungary's Paks-2 nuclear project is arranged via a new GRE, separate from government-controlled MVM that operates the existing Paks-1 nuclear plant. This helps to protect MVM's balance sheet. Of the €12.1 billion planned cost, €10 billion, or 80%, is going to be financed via an intergovernmental loan from Russia. The licensing delay was matched with a maturity extension. A similar scheme was used to fund Belarus' nuclear power plant. Another example: In 2016, Bulgaria's NEK managed to quickly obtain the loan from the government after losing litigation regarding the Belene nuclear plant. Still, the prospects and structure of a new nuclear power plant project in Bulgaria, where the aging Kozloduy plant supplies about 40% of the country's energy needs, is yet to be decided.

We believe one way for nuclear energy industry to proceed, which the sector is currently thinking about, is to qualify new projects as social goods under the EU framework. That way, they would be excluded from the existing energy market design and, more importantly, from state aid rules. This would allow for a more direct state involvement into new nuclear projects. We understand that designation as a social good may imply a specific framework with a determined remuneration scheme and eventually some form of separation from the rest of the utility's (unregulated or merchant) activities. Such separation could mean operating the nuclear asset at arm's length and with a separate, independent, governance structure.

As for revenue stability, most European nuclear plants are merchant-exposed, in contrast to renewables, which often enjoy favorable feed-in tariffs or attractive power purchase agreements (PPAs). Still, this is a policy decision rather than a feature of the nuclear technology, and some nuclear projects in Europe and elsewhere benefit from certain revenue-supporting mechanisms. For example, HPC in the U.K. enjoys contracts for difference that would help to stabilize revenues somewhat. Akkuyu nuclear in Turkey will get favorable U.S. dollar-denominated tariffs for a significant share of its output, in line with an intergovernmental agreement.

In Finland, TVO's existing and new nuclear plants (OL3) are based on the unique Mankala model, whereby shareholders commit to offtake energy and cover all costs of the project. We understand that a similar Mankala model would apply to the new Hanhikivi plant, which is awaiting regulatory approval to start construction. All recent new nuclear builds in Russia enjoy guaranteed returns on investment via long-term capacity payments (currently running for 20 years, with 10.5% guaranteed return on investment), similar in spirit to capacity supply agreements for other types of power generation (renewables, gas).

In October 2021, the U.K. government unveiled its plan to use RAB-based model for new nuclear construction to encourage private investment in the sector. Such a RAB-based structure could obviously provide a greater degree of comfort than current merchant-exposed remuneration. This is particularly true when it comes to decoupling revenues from volatile energy markets and providing long-term visibility to future cash flow. This would help attract investors and reduce the required cost of capital, which remains one of the key cost drivers for a new nuclear project. Ultimately, we believe this could significantly help the economics of the project. Yet we believe that for nuclear, RAB-based regulation can hardly be as strong as for networks because of unique technical risks, cost competitiveness--that could trigger reopeners--and the difficulty in predicting capital expenditure and costs needs, notably as regulation and safety requirements may evolve over time. At this stage, we also believe that the very long construction period (a decade) also makes it difficult to implement a timely and adaptive remuneration mechanism. As a result, while a detailed framework is yet to be designed, we believe it would be fairly difficult for such project to achieve levels of financial leverage similar (or close to) that of power grids.

What's more, and as previously mentioned, direct state support into the project would also significantly help the economics of the plant. We see several drivers, including generally a cheaper cost of financing (reflecting more that of the sovereign thanks to direct lending or guaranteed liabilities), eventually higher equity contributions and more important, better risk sharing among investors, notably when it comes to introducing a cap for investors to potential cost overruns. We also believe the treatment of end-cycle liabilities (including dismantling and more important waste management and storage) could also be part of state involvement, either by transferring these risks from the nuclear operator directly to the state or by providing a fair and timely remuneration to finance such liabilities over the course of the operating life of the asset. We see the management of these end-cycle liabilities as a very important topic to be addressed, both for existing and future nuclear plants. In particular, we see long-term storage solutions as a major risk for investors, given that even if a technical solution seems to work, no project has been effectively commissioned yet.

Appendix

Table 3

Rated Companies With Material Nuclear Exposure
Company Rating SACP where relevant Country(-ies) Nuclear capacity, GW % of nuclear in installed capacity Government-related entity

Atomic Energy Power Corp

BBB-/Stable bbb- Russia 30.3 100% Yes - 100%

EDF*

BBB+/Stable bb+ France 75.0 76% Yes - 83.68%

Engie

BBB+/Stable bbb+ Belgium 5.9 10% Yes - 23.64%

Centrica

BBB/Negative bbb U.K. 1.0 75% No

Vattenfall

BBB+/Positive bbb Sweden/Germany 4.6 41% Yes - 100%

Fortum

BBB/Stable bbb- Finland 3.2 20% Yes - 50.80%

Naturgy

BBB/Stable bbb Spain 0.6 21% No

Uniper

BBB/Stable bbb Germany 1.7 5% No

Teollisuuden Voima Oyj

BB/Positive bb Finland 1.7 100% No

MVM Magyar Villamos Muvek Zrt

BBB-/Stable bbb- Hungary 2.0 53% Yes - 100%

E.ON

BBB/Stable bbb Germany 3.8 9% No

EnbW

A-/Stable bbb+ Germany 2.7 10% Yes - 46.5%
Source: S&P Global Ratings.

Table 4

Examples Of Revenue Support Mechanisms For Selected Nuclear Projects Around The World
Revenue support mechanism Rated companies involved Expected commissioning date
Full coverage of costs (operating and capital expenditure) through Mankala pricing model TVO Teollisuuden Voima Oyj Beginning 2022 (versus initially 2009); construction start 2005.
Remuneration in line with existing nuclear fleet; ARENH price of €42/MWh for about 75% nuclear production and remaining exposed to market price EDF 2023 (versus initially 2012); construction start 2007
Merchant exposure MVM and will be built by Rosatom = Atomic Energy Power Corp. In 2025 and 2026; construction start in 2018 and 2019)
Capacity sales to ensure future payback; remunerated under the guaranteed return on investments principle (10.5% for 20 years). Potential extension of the payback period to 50-60 years with lowered 6.5% rate of return (ongoing). Atomic Energy Power Corp. In 2025 and 2027 (versus initially 2023 and 2024) ; Construction start in April 2018 and April 2019
Contract for difference (35 Years; price £92.5/MWh) EDF (75%) and China General Nuclear Power Group (25%) In June 2026 (from 2025 initially) with risk of delays of 15 and 9 months for units 1 and 2, respectively; construction start in December 2018.
No particular support mechanisms designated for the units, but industrywide supportive policy: 1) priority dispatch for nuclear power; 2) tariff to be determined unit-by-unit by negotiation between operator and local government, endorsed by NDRC, the central government's economic planning body. Assumption of 60 years' operational life. Chinese state-owned China General Nuclear Power Group In about 2022; construction start of units Nos. 3 and 4 in December 2015 and 2016, respectively.
MWh--Megawatt-hour. Source: S&P Global Ratings.

Chart 5

image

Table 5

Nuclear Policy In Selected European Countries
Selected countries Nuclear policy
Belgium Full phaseout by 2025.
Finland Nuclear power is expected to rise to over 40% by 2022, once Olkiluoto 3 comes into operation.
France Under French law, the Multiannual Energy Programme (PPE) plans for a reduction of nuclear in the electricity mix to around 50% by 2035.
Germany Full phaseout by 2024.
Italy No nuclear in the electricity mix.
Spain Gradual phaseout between 2027 and 2035.
Sweden Political debate around Sweden’s earlier commitment to ending nuclear.
U.K. The U.K.'s net zero strategy entails new nuclear projects and nuclear to reach about 15% of the electricity mix by 2040.
Poland As part of its decarbonization strategy, Poland aims to construct 6-9 GW of nuclear power generation by 2040 to replace coal units.
Russia Russia considers increasing the nuclear share from 20% to 25% by 2060 as part of its decarbonization strategy.
Source: S&P Global Ratings.

This report does not constitute a rating action.

Primary Credit Analysts:Elena Anankina, CFA, Moscow + 7 49 5783 4130;
elena.anankina@spglobal.com
Claire Mauduit-Le Clercq, Paris + 33 14 420 7201;
claire.mauduit@spglobal.com
Pierre Georges, Paris + 33 14 420 6735;
pierre.georges@spglobal.com
Research Contributor:Pauline Pasquier, Paris + 33 14 420 6771;
pauline.pasquier@spglobal.com

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