Sector And Credit Trends, Market By Market

• Western Europe is set to reduce nuclear generation, but with strongly diverging fates from country to country. While France advocates a gradual reduction in nuclear in its mix (to a still high 50% by 2035), it sees nuclear as playing (at least) a transitionary role over the next decades. By contrast, Germany's radical political decision to stop remaining nuclear output by 2022-2023, followed by the gradual phaseout of coal-fired generation (by 2038), will test bringing online major additional renewable capacity (potentially to 60% by 2030-2035 from 20% today). To ensure security of supply during the phaseout of more polluting energy sources, others, such as Spain and Sweden, favor life extension of existing nuclear reactors.
• U.S. nuclear operators (accounting for about 19% of the country's generation output in 2018) are under pressure from low-cost gas and renewables, which has already led to some nuclear capacity closures (even before their technical useful life). In response, policymakers are proposing initiatives for more support mechanisms, such as tax credits or zero emission credits.
• China, a major exception to global trends, is expanding its nuclear fleet to address growing energy demand, even though we believe it might be somewhat below its ambitious goal to increase operational capacity from 48.6gigawatts (GW) in September 2019 to 58GW by 2020, plus 30GW of nuclear construction in progress. Still, the share of nuclear in China's domestic mix was only 4.2% in 2018. Thanks to the experience the country has built up over the past decades and its development of a domestic nuclear industry, new nuclear builds are cost-competitive compared with costs of most other fuel types. The credit quality of nuclear companies will therefore reflect the balance between ambitious investments and state support.
• After the Fukushima nuclear plant accident in 2011, Japan is struggling to restart its idle nuclear reactors, with the objective of raising the share of nuclear back to about 20% by 2030 from 5% today. We believe achieving this target will be challenging given still harsh local sentiment; S&P Global Platts Analytics World Energy Demand Model forecasts that Japan's nuclear generation will represent only a 9% share by 2030. The country's slow regulatory approval process as well as massive costs to upgrade facilities to meet stringent safety requirements are high huddles for the Japan's regulated power utility companies. On the other hand, we take the view that the Japanese government's recent revision of the pricing mechanism so that nuclear operators can pass through additional capex is supportive for the companies. We take the view that the companies' credit quality will continue to depend on the restart of the idle reactors.
• Korea, one of the most reactor-dense countries globally, has been since 2017 dramatically shifting to renewable energy sources from coal and nuclear. Due to post-Fukushima safety concerns and as part of the green agenda, the government tightened safety requirements for reactors and decided not to approve any further extensions of nuclear plant life. Meanwhile, the construction of previously started reactors continues, and Korea has commissioned two new reactors this year.
• In Russia, nuclear generation benefits from vertical integration as well as supportive government policy and market design. While its ambitious international expansion strategy poses risks, the Russian nuclear company's solid financials and government funding for international projects provide some comfort.

(See the related report : "The Energy Transition: Nuclear Dead And Alive," Nov. 11, 2019)

Table 1

Chart 1

Chart 2

The U.S.: Competition And Volatile Markets

At 98GW, the U.S. has the largest nuclear-driven power generation fleet with about 98 active nuclear reactors. While nuclear units comprise only about 9% of the installed capacity of the American power fleet--roughly split among regulated (54GW) and merchant (43GW) markets--they generate a much higher 19% of aggregate (megawatt-hour) MWh because nuclear units run at over 90% capacity factors. Importantly, they also represent about 60% of the market's CO2 emissions-free power production. Currently, solar and wind combined produce about 8% of energy generated with about 51GW and 95GW of installed capacity. To replace nuclear, which generates about 19% of U.S. power (or about 2.4x currently by wind and solar), by 2030 or 2035, renewable deployments would have to be over 20x and 15x current annual deployment rate. Nuclear power is a zero-emission resource and assists in carbon mitigation. To illustrate, an average coal plant with 500MW capacity operating at a capacity factor of 55% generates 2.5 million tons of CO2 per year.

Chart 3

Nuclear retirements have accelerated

The combination of sustained low natural gas prices, penetration of zero-marginal-cost renewable resources, and a slowdown in electricity demand growth, has eroded the economics of base-load nuclear generation.

This already led to 5.9GW (seven plants or 6.1% of total) early closures in the past six years--that is, before the end of a typical 60-year reactor life. An additional 8.5GW of capacity has announced retirements, while more are in the "at-risk" category. In comparison, between 2010 and 2018, only one new nuclear power plant came online in the U.S. (TVA's 1.2 GW Watts Bar Unit 2 in 2016).

Table 2

Revenues, not operating costs, are the key issue

In the PJM (Pennsylvania, Jersey, Maryland) market, average power prices fell by almost half over 2007-2017 to $31 per megawatt-hour (/MWh) from $62/MWh. This compares with average costs (including capex) for American nuclear generation of $33.555/MWh in 2017.

After increases in costs in 2008-2015 (due to fuel rod storage incremental costs, duplication of on-site auxiliary power, as well as life extensions), operators have become leaner and efficient thanks to a combination of upgrades, shorter outage durations for refueling or maintenance, and balance-of-plant thermal efficiency improvements. This led the U.S. nuclear power fleet in 2018 to see its highest capacity factor on record, 92.6%, further helping to lower fixed operating costs on a per megawatt-hour basis (see table 3).

Table 3

We have identified a few factors that are contributing to this "missing revenue" problem:

• Competition with gas. The declining marginal cost of natural gas and technological breakthroughs in turbine technology has lowered power prices.
• Increased renewables penetration. Federal and state mandates for renewable generation suppress prices, particularly during off-peak hours when wind generation is highest and electricity is needed the least. As wind generation has proliferated, instances of negative or very low prices have become more frequent. For example, across 14,700 hours since January 2018, we've observed 203 hours with negative prices in PJM's NI-hub region and over 500 hours when prices were less than $10/MWH. Furthermore, production tax credits create an incentive for wind generators to bid negative prices of up to a negative $23/MWh.
• Relatively low to no growth in electricity demand due partly to subpar economic performance since the 2008 recession, but also due to greater energy efficiency and distributed energy resources (behind-the-meter solar, for instance).
• Transmission constraints, which require a power plant to pay a congestion charge or penalty to move its power onto the grid (up to $2-$3/MWh for certain congested operators).

With the entry of new, near-zero marginal cost renewable resources and reductions in the marginal fuel costs of natural gas, electricity prices are likely to stay low most of the time without the variation and price spikes seen historically, making it difficult for nuclear base load generation, which is high capital and low marginal cost in nature, to generate sufficient profits. Most existing (and upcoming) renewable energy avoids this problem entirely by operating outside of electricity markets through long-term contracts, which nuclear energy does not generally use.

New policy initiatives in support of nuclear see daylight.

Lately, we have seen several examples of state support for the nuclear industry where nuclear units are compensated for the revenue shortfall in some shape or form. There has been a structural shift in regulators' awareness of the distressed nature of the nuclear industry and their willingness to act. Decisions have been made for a variety of reasons such as fuel diversity, clean generation, and grid and resource reliability issues. Also, decisions at the state level have been influenced by the need to preserve local generation assets to avoid affecting regional employment and the tax base.

Table 4

One recent example is nuclear subsidies by way of zero emission credits (ZEC) through the Clean Energy Standard (CES) in New York and the Future Energy Jobs Bill in Illinois. Subsidy sizes vary by state, based on the social cost of carbon and avoided emissions, and some states like New York use escalations.

These decisions were appealed by independent power producers who argued that the programs were anticompetitive and impinged on the Federal Energy Regulatory Commission's authority. The state rulings were upheld in federal circuit courts, and the U.S. Supreme Court declined to hear further appeals. With these rulings, the momentum has clearly shifted in favor of nuclear generators. More requests for ZECs have been approved in New Jersey, Connecticut, and Ohio. There are also state lawmaking efforts at various stages of development in Pennsylvania and Illinois.

Nuclear subsidies are sparking debates about efficiency and fairness. On the one hand, subsidies could distort economic competition between generating technologies; on the other hand, an affordable and reliable energy supply is essential for socioeconomic development. And, similar to renewables, CO2 emission avoidance should benefit from a carbon price.

Will such policies provide support for at least life extensions, now that new nuclear builds have become too risky?

The question of support will be critical not just to avert early closures, but also as to whether future license extensions will be pursued and granted.

As nuclear has been established the longest in the U.S., the average age of its plants is almost 40 years. According to the International Energy Agency, by 2030, 24GW (nearly one-quarter) of this capacity will need to obtain extensions to operating licenses or shut down; another 62GW will reach the end of their operating licences by 2040. While most reactors in the U.S. already have been granted a 60-year operating span, of these, six reactors have submitted applications to seek extensions to operate until 80 years.

Given the challenges in building new plants (see box "New U.S. Nuclear Projects Have Suffered Major Cost Overruns, Making More New Builds Highly Unlikely"), future support for and decisions about life extensions will be a critical factor.

Still, according to S&P Global Platts Analytics, the share of nuclear could fall only slightly down, to 18% in 2030 from 19% today. Absent any energy price reform, we see a scenario where nuclear could be down to 15% by 2030.

EMEA: ESG And Aging Nuclear Fleets Mean A Gradual Decline In Nuclear

The Fukushima disaster questioned the risks of nuclear in Europe, leading to drastic exit in Germany and cost inflation. Fukushima, which occurred, 25 years after Chernobyl, shed new light on risks associated to nuclear in Europe. This resulted in a more general change of mindset, with two highly visible effects. The first was more stringent security and safety requirements for nuclear sites, which has been leading to significant cost inflation and investments for operators to meet the new standards and maintain their licenses to operate—so much so that the profitability of nuclear power is uncertain under certain market and fiscal conditions, especially compared with that of other energy sources, including renewables. The second was the decision by the German government to completely exit nuclear by 2023, a significant and costly decision for the country, mostly driven by environmental, social, and governance (ESG) considerations. (See the related report: "The Energy Transition: What It Means For European Power Prices And Producers," Nov. 7, 2019

Ambitious goals for the growth of renewables will gradually reduce the share of the existing nuclear and coal baseload

The EU has set an ambitious objective of reaching 32% of final energy consumption from renewables by 2030 (compared with 17.5% in 2017). This, together with its goal to achieve 32% of energy savings--which supports a rather flattish power demand curve over the coming decade--puts pressure on baseload power production and explains the expected declining share of nuclear and coal.

Although many Western European countries have relied heavily on nuclear, most of them either envisage a gradual reduction (France and Sweden, for example), while others target shutting down reactors completely as soon as 2022-23 (Germany) and 2025 (Belgium), and Spain plans a phase-out over 2025-2036. In Europe, only France, the U.K., and Finland have new nuclear projects under construction, but each are facing massive cost overruns and delays (see Box "Europe Is Unlikely To See Additional New Nuclear Builds, Given Massive Cost Overruns And Execution Risks"). Hence we believe new nuclear builds are likely to be the exception rather than the rule. Interestingly, several Eastern European countries envisage new nuclear projects, given security of supply concerns, their currently high share of coal-fired generation, and often limited potential for solar and wind given their less favorable geographic and climate patterns.

Chart 4

The advanced average age of the nuclear fleet means a reset date for European nuclear policies

A large part of the European nuclear fleet was built in the 1980s and early 1990s, with an initial operating period set at 40 years. To continue operations over the coming decade, new licenses need to be obtained and heavy investments need to be made. Beyond technicalities, these extension permits have taken a very political and social turn in each country, raising questions about the future of nuclear energy. Negotiations between operators and governments have so far not only led to new timeline for a gradual nuclear phaseout but also better economics (notably reduced fiscal pressure) for remaining nuclear in exchange for the required investments for life extensions, which were paramount to ensure security of supply. The high average age of the European reactors also puts into question their operating performance, maintenance requirements, and reliability, with more frequent and longer outages. This has been particularly true in France, Belgium, and the Czech Republic, where long and unexpected outages have increased risks for the performance of the overall electric systems in recent years.

Longer-term security of supply, grid stability, as well as affordability concerns explain why a phase-out will likely be only gradual and potentially delayed

By 2022 the removal of the remaining 8GW of German reactors will be a first test for how the country will cope with the intermittent nature of renewables. Based on forecasts from S&P Global Platts Analytics' European Electricity Five-Year Forecast (October 2019), Germany should become a net importer of power to the order of 26TWh (3GW equivalent) on average in 2025, compared with its current net export balance of 38TWh (4.3GW) on average in 2019.

Belgium's plans to exit 5GW in nuclear by 2025 seems difficult, bearing in mind nuclear accounts for more than 40% of the country's power consumption. This means that the rapid phaseout would create an energy gap amounting to about 3.9GW (most likely of gas-fired plants) by 2022 as per estimates of the national TSO Elia. Moreover, past governments have expressed a concern that this should not push up the country's already high power costs.

Spain already pushed back the phaseout of its nuclear capacity (7GW) to between 2025-2036, and even if nuclear output represents between 20% and 22% of total generation, Spain is probably better positioned given its potential for additional competitive solar plants.

We also expect that from 2030 onward several existing French nuclear plants will come offline, which may raise concerns about the security of supply in certain markets, unless major technological progress is made in terms of storage and attractive capacity-based remuneration has been put in place.

Support mechanisms can help to keep nuclear afloat

Credit-supportive measures are being considered to support further nuclear generation before renewables can take over. In France, the government and EDF are advocating to the European competition authorities to re-regulate its existing nuclear fleet to support the huge life extension investments needed to provide better visibility and cash flow predictability. This would mean a higher price range than currently embedded in the regulated tariff (ARENH) of €42/MWh. According to a report from the Cour des Comptes, the full cash cost of producing nuclear is assessed at 60/MWh.

The U.K. government has signed a contracts for difference (CfD) with EDF on Hinkley Point at a guaranteed strike price of £92.5/Mwh (2012 value, and to be inflated as per consumer price index. This is somewhat similar to the pricing in certain renewable projects.

A country by country perspective

France, the country that relies the most in the world on nuclear production with about a 72% contribution in its power output, has set a target of lowering this to 50% by 2035. The new energy and climate law, adopted in September 2019, confirms a modest reduction to 58GW from 63GW currently by 2030, with no preset closures due before 2027, at a pace of one reactor closure a year. This is to allow full utilization of the nuclear fleet with major ongoing life extension investments (€45 billion over 2014-2025 to extend the life of the entire nuclear fleet to 50 years), while factoring in the targeted ramp-up of renewable capacity (with an 11GW increase planned by 2023 and a further 13GW by 2028). We expect the new energy plan to be neutral for EDF's credit quality as it doesn't constitute a major deviation in its current strategy, with limited closures in the coming decade. A bigger challenge for EDF and the system will likely be the removal of up to 12.6GW in nuclear capacity between 2027 and 2035.

In Germany, the nuclear phaseout program will be completed much sooner, with final closures of nuclear operations required in 2022. The German parliament approved an acceleration of the phaseout back in 2011, pressured by growing public opposition toward nuclear energy. Following the Fukushima disaster, 8.3GW of nuclear capacity (eight plants) was immediately halted. About 8GW combined net capacity from seven reactors are still in operation and are to be removed by 2022. This is prompting a continued rapid evolution of the German mix, notably as it is combined with the embarked coal phaseout, which will see 13GW halted by 2022.

We assess that this accelerated phaseout will lead to a significant reshuffling of the German energy landscape (the breakup of E.ON and RWE most notably). Only several years after the accelerated plant closures did a court rule to indemnify the operators for lost production. At the same time, nuclear waste liabilities were successfully transferred to the German federal government against payment to the German Nuclear Waste Disposal Fund ("Fonds zur Finanzierung der kerntechnischen Entsorgung") in 2017 for a total of about €23 billion (a roughly 35% risk premium above the amounts provisioned by the companies). The offloading of long-term waste provisions from the generators' balance sheet was nevertheless credit positive, because storage costs remain particularly subject to uncertainty--a risk now borne ultimately by the German government. (Decommissioning costs remain on the account of the operators but are in our view more predictable).

Spain, similar to France, has decided to slow the nuclear phaseout with shutdown of its 7.1GW nuclear power plants, now set between 2025 and 2036, paving the way for the end of nuclear energy in the country in 2036. Under the Spanish framework, all nuclear liabilities lie with the state agency, ENRESA (Empresa Nacional de Residuos Radiactivos), with plant operators only responsible for pre-decommissioning commitments. The plants contribute to their decommissioning prior to their shutdown through a fee on nuclear generation. The current installed capacity in the market (with a significant share of underutilized CCGTs or combined cycle gas turbines) together with the expected renewables that will be developed over the next decade, should ensure a smooth transition in our view. Therefore, we believe the nuclear phaseout to be largely neutral for Spanish players Iberdrola and Endesa.

The Belgium nuclear phaseout is still due to be completed by year-end 2025, with a reduction of 1GW in 2022 and 1GW in 2023; and a gradual reduction in 2025 of 0.4GW in February, 1GW in June, September, and October, and 0.4GW in December. As mentioned above, the key question remains how the market will cope with security of supply.

The U.K.'s nuclear fleet (9.3GW installed capacity, 18% of output) is aging, and about half of nuclear capacity is expected to be decommissioned by 2025. Under the U.K.'s long-term energy strategy, nuclear power, along with renewable energy should continue to play an important role in the U.K.'s energy mix over the next few decades. Nonetheless, EDF's Hinkley Point C (two reactors with combined capacity of 3.2 GW) is currently the only approved nuclear power station and is already incurring important cost overruns and delays (see box "Europe Is Unlikely To See Additional New Nuclear Builds, Given Massive Cost Overruns And Execution Risks"). Also, the withdrawal of Hitachi in January 2019 from the Wylfa project, following too high construction costs, reflects the severe challenges faced by companies in executing nuclear projects.

Sweden has an official phaseout target for nuclear generation set in 2040, even if we understand the decision is not entirely definite. While the country started reducing its nuclear fleet, its has also embarked on a capital-intensive life extension program of its relatively old fleet (36 years on average, compared to about 33 year for EDF). In 2015, the country decided to close old reactors (40-45 years) based on economic reasons, when high fixed production costs were above very low market prices and large investments were needed to maintain them in operations.

Finland is adopting a different stance regarding nuclear power, with the construction of a third (OL3, 1.6 GW) and potentially fourth reactor (Hanhikivi, 1.2 GW), highlighting the strategic aim of reducing the country's reliance on electricity imports. When OL3 will be operational (July 2020 according to the latest TVO guidance), Finnish nuclear generation will meet about 40% of Finnish consumption (from 25% currently), effectively alleviating the import level (23% of its consumption in 2018).

In Eastern Europe, the Czech Republic, Slovakia, Bulgaria, and Hungary are set to keep a relatively large share of nuclear in their energy mix so that the countries remain self-sufficient in energy production. Many of these countries are significantly reliant on coal, and their renewable production other than hydro is nascent. They view nuclear as a way to reduce dependency on Russian gas and on coal-fired generation to reach their CO2 goals. To mitigate credit risks, the Czech government is considering whether the state would provide loan guarantees for the potentially large nuclear replacement when CEZ's Dukovany nuclear power plant ceases operations in 2035. At this stage, it remains unclear whether the Czech government would absorb the potentially large capex related to the new nuclear project, or if this cost would fall on CEZ's balance sheet. We understand that Paks nuclear project in Hungary will likely be funded with intergovernmental loans.

Meanwhile, Lithuania now imports about 70% of its electricity after it had to close its Ignalina nuclear power plant in 2009, due to EU pressure about safety concerns.

Finally, Ukraine generates over half of its electricity from nuclear, and views it as essential for the country's energy security, due to the geopolitical risks of Russian gas and continuing high reliance on coal. In early 2000s, Ukraine commissioned new nuclear capacity to replace Chernobyl and continues to perform life extensions and upgrades for most of its reactors, although due to financing constraints, in our view it is less certain whether the country will proceed with building new reactors to replace existing ones or complete construction already started.

China: Nuclear On The Rise

China has the world's fastest-growing nuclear generation fleet, and government policy is supportive of nuclear generation as demonstrated by priority access to the grid and supportive regulation for waste management. Nuclear generation is cost-competitive compared to other fuel options, thanks to low construction costs achieved with local design and vertical integration.

Nuclear and renewable growth go hand in hand with an aim to reach (a still modest) 20% of primary energy (and 50% of power output) by 2030

China is on a long journey of transforming to cleaner energy and more sustainable economic growth. The nation is committed to cutting its CO2 emissions per unit of GDP by 60%-65% by 2030 from the 2005 level and increasing the share of non-fossil fuel in primary energy to 20% by the same date. China also set a strategic and long-term goal of achieving 50% of electricity from non-fossil fuels by 2050. After strenuous efforts in recent years, China is close to reaching its near-term target of 15% of non-fossil fuel in the energy mix by 2020. That said, coal still accounts for 58% of its primary energy and 67% of electricity generation in 2018.

Chart 5

To achieve the task of cleaner energy, lower carbon emissions, and security of supply, we believe China will continue to significantly develop both renewable energy and nuclear power. After tremendous growth of renewable energy in the past decade, bottlenecks of resource constraints and of solar and wind intermittency have started to emerge, while the breakthrough in energy storage is less visible in the near term. In addition, the growth of renewables is likely to embark on a more stable growth when China may end subsidies and attain on-grid renewable tariffs on a par with those for coal power.

In our view, nuclear power, continuing to fall under stringent scrutiny over its safety and security, is likely to grow faster in 2020-2025 and play an important role in China's energy transformation. Nuclear power in China accounted for only 2.0% of primary energy in 2018 and 4.1% of electricity, which is below the global average. Still, China is the fastest-growing nuclear fleet in the world. In 2018, 74% of the increase in global nuclear generation came from China, and total operating capacities of nuclear power reached 48.6GW in September 2019 after 10 new units have been commissioned in 2018-2019.

Domestic designs pave the wave for accelerated growth.

China may slightly miss its goal of increasing its operating capacity to 58GW and 30GW in construction by 2020 as it has not approved any new builds during 2016-2018. After the Fukushima nuclear accident, China requires third-generation (G-III) or more advanced reactors for new builds. Three first-of-its-kind (AP1000 and EPR) G-III reactors of foreign design have been completed and started commercial operation in the second half of 2018. However, they incurred significant delays and cost overruns, making the policymaker very prudent in approving new builds. The AP-1000 pressurized water reactors Sanmen-1 (designed by now bankrupt U.S. Westinghouse) was delayed by four years and incurred 70% cost overruns, while the European pressurized reactor Taishan (EPR designed by EDF's Framatome) was delayed by three years, with an estimated 30% cost overrun.

In contrast, the construction of China's own G-III HPR1000 reactors are on track with scheduled commission as early as in 2020, which paves the way for accelerated growth of nuclear power. In 2019, three units of new reactors (totaling 3.4GW) were approved for construction so far, in which two are HPR1000 reactors (developed from G-II PWR (pressurized water reactor) long used in China) and another is the CAP1400, the enlarged version of AP1000 with Chinese intellectual property rights. In our view, the prolonged trade tension between the U.S. and China and the expected long-term technology confrontation of two nations may reshape China's choice of nuclear power technology. We gauge China may prioritize the reactors of HPR1000 and CAP1400 for new builds.

China has established a complete supply chain, technological capabilities, and engineering and construction capacity that positions it in better cost control of nuclear power investments. Furthermore, vertical integration of design, construction, operation, and maintenance by two major nuclear power groups help to coordinate and manage complex nuclear power plant (NPP) projects. In particular, construction costs of recently completed Generation II reactors were between Chinese renminbi (RMB) 14,000-15,000 per kW (equivalent to roughly $2000/kW, well below new build costs in developed markets, while new Generation III reactors are budgeted at RMB17,000-18,000 (about $2,500-$2,600). This compares to construction costs of RMB6000-RMB7000 per kW for wind and RMB4000-RMB5000 per kilowatt for solar in China at present.

Support for nuclear stems from priority grid access, cost competitiveness even at prices set by coal fired-generation.

As a source of clean energy and base load electricity, nuclear power is well supported by the government in generation dispatch to grids with priority before coal power. The regulator also sets the province-based minimum utilization hours policy to ensure reasonable consumption of nuclear power for maintaining relatively high operational efficiency. In 2018, the average utilization of nuclear power was 80%, compared with 50% for thermal power, 24% for wind, and 13% for solar.

According to the research institute affiliated to Datang Power, the LCOE (levelized cost of energy, that is, net present value of capital costs and operating costs over the asset's lifetime divided by total energy production) of nuclear power is ranked the second lowest in China, only higher than hydropower. The current regulatory regime essentially places nuclear power as cost-competitive as coal power as it defines the on-grid tariffs of nuclear power as the lower of RMB0.43/kWh and local benchmark coal power tariffs. This means when coal power tariffs are adjusted, nuclear power tariffs (capped at the ceiling) would follow. Despite the higher costs of first AP1000 and EPR projects in China, their approved tariffs are only marginally higher than local benchmark tariffs for coal power, leading to their lower project returns than existing G-II units. Partly mitigating this is the longer design life of G-III (60 years) than G-II (40 years).

Another threat to the profitability of Chinese nuclear power operators is the increasing volume of generation traded on a competitive market basis, therefore exposing them to moderate price risk. The volume not under market trade (still about three-quarters of the total) is protected by the preset on-grid tariffs. In 2018, China General Nuclear Power Corp. (CGNPC) had 23.8% nuclear power generation traded on market, the ratio was 27.0% for China National Nuclear Corp. (CNNC). Against the backdrop of increasing competition in the power market, prices of market-traded volumes generally have to be discounted, tending to weaken the profitability of operators.

The credit quality of nuclear operators is further supported by state ownership and funding

Nuclear power is heavily regulated in China from project inception and central oversight to approval, to ensure safety and security, unlike renewables projects where approval is delegated to provincial governments.

In China, the two main nuclear operators are CGNPC (A-/Stable/--) with 23.2GW of capacity and CNNC (not rated) with 19.1GW. The state also orchestrated them to merge their designs of Gen-III into HRP1000, the national champion.

The capital-intensive nuclear projects are primarily funded with long-term syndicate loans from government-backed banks with favorable terms and sometimes with power sales revenue as collateral. Chinese nuclear power groups also actively tapped both bond and equity markets for funds. In 2014, CGNPC raised Hong Kong dollar (HK$) 23.8 billion (about US$3.0 billion) from its Hong Kong IPO, and another RMB15 billion from its IPO in China this year. For CNNC, it raised RMB13 billion from its IPO in 2018. At the project levels, most NPPs also have minority shareholders, most of which are local power generation groups controlled by provincial governments.

With very strong government extraordinary support, the credit strength of NPP operators in China remains stable, though their balance sheets have relatively high leverage. The companies have reaped experience commercializing the first few Gen III units. Solid operating cash flow and a manageable cost of funding should mitigate the impact of sustained high capex and growing debt.

Finally, nuclear waste management--in particular spent fuel--is a thorny issue. This, in addition to operational safety, creates considerable environmental hazards for generations to come. China's response to this issue has been more neutral: keeping R&D on fourth-generation units that run on recycled fuel, while keeping the spent fuel safeguarded on-site. Currently, the responsibility for waste handling lies explicitly with the central government (that nuclear operators pay for through for a levy of RMB 0.026/kWh). However, the storage burden lies with the nuclear operators, for waste is stored on-site after being taken out every 12-18 months.

Japan: Back To Nuclear Is Not An Easy Path

In our view, nuclear power will likely remain an important part of Japan's energy mix, as other alternatives are unlikely to be sufficient to satisfy the country's energy demand.

The government's objective to raise the share of nuclear back to 20% from 6% today depends on the restarting of reactors

In Japan, there has been strong awareness of the risks of nuclear power after the Fukushima No.1 nuclear accident by Tokyo Electric Power Company Holdings Inc. (TEPCO; BB+/Stable/B) in 2011. However, the limited room for transmission and distribution capacity nationwide and high cost of solar and wind power generation limit the role of renewable power. In 2018, the Japanese government and regulator revised the 2030 target power generation mix. Under the new plan, Japan is still aiming to raise the contribution of nuclear to about 20%-22% in 2030, from about 6% in 2018. The government estimates that the cost of nuclear power generation (Japanese yen (JPY) 10.1/kWh or about $9.4/kWh) remains lower than coal (JPY12.3/kWh) and LNG (JPY13.7/kWh).

Chart 6

Chart 7

Therefore, we believe that Japanese regulated electric utilities will aim to increase their nuclear power generation by restarting nuclear reactors that were idled after the Fukushima accident. However, target achievement requires more than 30 reactors to operate, which in our view will challenging to achieve given that S&P Global Platts Analytics World Energy Demand Model forecasts Japan's nuclear generation will only account for 9% by 2030. The Japanese regulatory approval process will highly likely take a long time, taking into account the stringent safety requirements and local residents' harsh sentiments (see box "Restarting Idle Nuclear Plants In Japan Is A Lengthy Process, Not To Be Underestimated"). Also, we believe such an effort will require additional huge costs, which will weaken their profitability and operating cash -flow over the years to come. The necessary capex and expenses for Japan's nuclear operators to meet the regulators' additional safety standards to protect against potential severe natural disasters or terrorist attacks are estimated at around JPY4.8 trillion ($44 billion) in total, three times the 2013 level.

We believe such pressure could be somewhat mitigated by the Japanese government's supportive pricing scheme for decommissioning. The regulator recently allowed the nuclear reactor operators to pass decommissioning costs through to tariffs over the long term. As a result, in our view government support could somewhat mitigate the additional cost burden for the nuclear reactor operators.

Growth in renewables has run into limitations and affordability concerns, leaving LNG as an option.

In Japan, renewable energy has made successful inroads into the country's energy mix, but sustaining growth is facing challenges. In addition to physical constraints (transmission connections and land and resource availability), renewable power has also remains more expensive than nuclear. After seven years since the introduction of feed-in tariffs (FIT) to promote renewable energy, in particular solar power, the customers' electricity bill has steadily increased. High-cost renewable energy and additional costs to strengthen transmission and distribution facilities, to sustain unstable renewable energy, weigh on the customers' monthly bill. This has started to impede the promotion of additional renewable power generation. Even though the regulator gradually lowered the FIT price from JPY40/kWh in 2012 to JPY18/kWh (equivalent to $0.4/kWh and $0.2/kWh) in 2019 for large-scale solar power generation, the price remains almost twice that of key European countries.

Following the increasing pressure to shift to environmentally friendly energy, the Japanese regulated utility sector takes initiatives seriously to curb CO2 footprints. The industry is cautiously reviewing or considering suspending its new construction of coal-fired power plants.

Aiming to balance 3E+S (energy security, efficiency, environmental friendliness, and safety), we believe Japanese electric utility companies will be forced to further shift to LNG-fired or gas-combined power plants to find a better balance between fuel costs and CO2 emissions. Low global prices for liquefied natural gas (LNG) could enhance the cost advantages of Japan's gas-fired generation compared to nuclear power generation.

Russia: Nuclear Expertise And State Support Underpin Continued Development

Nuclear to keep a stable share in the fuel mix

We expect nuclear to remain an important and broadly stable part of Russia's generation mix (19% in 2018), in line with the government's policy to gradually replace old aging RBMK-type reactors with new VVER (pressurized water reactors) ones, and to proportionately increase all types of generation to meet incremental electricity demand growth. Despite ratification of the Paris Agreement in September 2019, environmental issues are not on top of Russia's policy agenda, and penetration of renewables other than hydro remains very limited, at below 1% of power generation mix. We expect nuclear capacity replacements to proceed, but expansion potential to be limited by demand constraints, given the country's only modest GDP growth of 1.7%-1.8%, as illustrated by the recent decision to delay construction and commissioning of certain new projects. In addition, there could be potential for small modular reactors in remote areas (as illustrated by floating station Akademik Lomonosov, 70MW capacity, started in 2019), but they remain an exotic and relatively expensive option. All Russian nuclear power plants are owned and operated by state-owned vertically integrated monopoly Atomic Energy Power Corp. JSC (AEPC; BBB-/Stable), a civil arm of the 100% government-controlled State Corporation Rosatom (not rated).

Chart 8

Supportive government policy

The Russian government's policy is supportive of the nuclear sector, as the natural potential for renewables is low while local vertically integrated nuclear offers a cost-efficient and import-independent baseload option. Domestically, nuclear capacity supply agreements support investment payback and a 10.5% return over 25 years. Although other types of generation such as thermal enjoy a similar support mechanism, for nuclear, a larger part of the all-in electricity cost is related to capital spending. As a result, about one-third of AEPC's EBITDA in 2017 came from capacity payments. Also, nuclear has priority access to electricity market and less exposure to low regulated heating prices. This supports a solid EBITDA margin compared to other fuel types. In line with Russian law on nuclear waste, AEPC is only officially responsible for nuclear liabilities accumulated after 2011, and the rest is a financial responsibility of the government, leading to a low company liability ($2.1 billion on balance sheet only). In addition, being a government-related entity, AEPC enjoys ad hoc equity support for new NPP projects, which are not essential for the company's financial metrics, but still positive.

Nuclear is cost-competitive vis-à-vis that of other fuels

Russian nuclear generation is cost-competitive vis-à-vis that of other fuel types, thanks to relatively low construction costs, low additional nuclear-related costs, and high capacity utilization. Nuclear output is sold at prevailing market prices, which effectively depend on gas-fired and coal-fired generation costs, but result in solid profitability for nuclear generation. The relatively low cost of construction stems from the lasting effect of ruble depreciation in 2014, as well as vertical integration, as well as learning gains and the serial effect from several recent new builds. AEPC and its parent Rosatom are vertically integrated through the value chain, from uranium mining and enrichment to fuel production, NPP construction, and electricity generation. This helps to coordinate large, long-term and complex projects related to NPP construction. Also, in contrast to Western Europe where very little new nuclear capacity was made operational after the 1980s, AEPC and its sister companies have a recent experience of successfully completing several technically similar NPP projects in Russia and abroad (for example, Novovoronezh-2-1 in Russia and Kudankulam-2 in India in 2016, Tianwan-3 in China in 2017, Tianwan-3 in China and Rostov-4 in Russia in 2018, and Leningrad-2-1 in Russia in 2019).

International nuclear power plant construction is a major risk

An ambitious growth strategy with 36 international nuclear power construction projects are the key risks to AEPC's credit quality. Of these, AEPC is directly involved in two, Hanhikivi in Finland and Akkuyu in Turkey. The rest are performed by sister government-controlled entities, but AEPC is typically indirectly involved in providing services or in subsequent sales of nuclear fuel under long-term contracts, and in our view, would be exposed to reputational risks in case of project execution issues. The Russian government views international nuclear projects as a way to support the country's economic growth via the export of nuclear construction services and the subsequent export of nuclear fuel under long-term contracts. Many new projects therefore are funded with intergovernmental loans or loans from Russian government-related banks to the host countries that are set to own the assets. Despite a positive recent experience with similar reactor models already operating in Russia, and although AEPC mostly focuses on developing countries with more nuclear-friendly policies and regulations, we cannot rule out delays or cost overruns, for example, driven by regulatory differences or local conditions. For example, we understand that the Hanhikivi project in Finland experiences delays with obtaining necessary regulatory permits and will not be able to meet the initial completion target of 2023, but as long as AEPC's costs are limited to design and preparation of application documents, this actually delays a heavy capex phase.

Appendix: Rated Companies With High Exposure To Nuclear

Table 5

Related Research

• The Energy Transition: Nuclear Dead And Alive, Nov. 11, 2019
• The Energy Transition: What It Means For European Power Prices And Producers, Nov. 7, 2019
• The Energy Transition: Renewable Energy Matures With Blossoming Complexity, Nov. 8, 2019
• What Makes Russia's Nuclear Sector Competitive, July 11, 2019