nuclear subsidies

The 2023 edition of the World Nuclear Industry Status Report (WNISR 2023) once again provides a comprehensive review of industry growth, performance, and political and economic drivers around the world. This has always been a huge undertaking, but is made ever more so by a continuing migration away from critical analysis of nuclear power by many of the traditional funders supporting analysis of nuclear policy. My personal view is that careful evaluation of the economic, political, and environmental aspects of all energy pathways remains critical in helping us make good choices and avoid big problems. The importance of these reviews grows as niche ideas start to scale since sometimes side-effects that can be ignored during early research and pilot phases become big problems once the production base is big. This is a large issue with biofuels, where growing scale increases conversion of natural habitats and the diversion of staple crops from food and feed sectors into energy.  For nuclear, there are trade-offs on cost and timing of delivery in addition to the proliferation concerns that remain.

I was happy to be able to contribute to the WNISR 2023 effort, writing the Economics and Finance section of the paper. Key findings and extracts from that section are presented below. 

Economics and Finance Chapter   WNISR 2023 Full Report   

 WNISR 2023 Global Launch Slide Pack   

Nuclear's continuing economic challenges

The engineering allure of nuclear is understandable given it is a compact, high load-factor and low-carbon power source. These attributes are desirable in a world with growing demand for energy and increasingly dire concerns about greenhouse gas emissions. Public pronouncements touting these benefits are common (this one says nuclear is the "only" solution to climate change). At the recently concluded COP28 meetings, nuclear was specifically included for the first time since the meetings started in 1995, with a global commitment to triple capacity. The International Atomic Energy Agency noted that

the inclusion of nuclear, together with a separate declaration made last week at COP28 by more than 22 countries to advance the aspirational goal of tripling nuclear power capacity by 2050, as well as statements by the IAEA and the nuclear industry, underscored the momentum building behind the world’s second largest source of clean electricity.

But the economic challenges that have plagued nuclear's growth for more than a half-century remain. The sector continues to struggle with rising costs, which, combined with long construction delays, has made investors wary. While routinely including cost reductions from learning (the "Nth of a kind reactor, or NOAK) in cost projections and modeling of decarbonization scenarios, these gains remain largely speculative rather than empirical. The sector has had much lower learning curves than its competitors in recent years. Between 2010 and 2021, the global-weighted levelized cost of energy (LCOE) for utility scale PV dropped by nearly 90 percent, by nearly 70 percent for concentrating solar power and onshore wind, and by 60 percent for off-shore wind.  Lazard’s U.S.-focused analysis of LCOE shows significant declines since 2009 (83 percent for utility scale solar and 63 percent for onshore wind) as well, despite an uptick in costs during 2022–2023. In contrast, the LCOE for nuclear has risen 47 percent over the same period.  Even in the elevated growth scenarios for nuclear that are now being discussed, the unit counts remain orders of magnitude lower than competitors, providing a much smaller base for learning, materials substitution and evolution, production scale, and workforce development.  

 The result has been a push for ever increasing "policy support" -- simply a polite way to say "massive government subsidies."

Further, innovation within the power sector and increased ability for loads to time shift their demand has already put even operating reactors (where much of the capital cost has already been paid off) under competitive pressure. These pressures are likely to increase going forward. The result has been a push for ever increasing "policy support" -- simply a polite way to say "massive government subsidies." Though the form is not identical across countries, subsidies have been provided in virtually all countries and stages of the fuel chain.

Operating reactors rely on regulated rates or state subsidy to stay in business

For decades, proponents have characterized nuclear power as “expensive to build but relatively cheap to run”. The characteristics driving this claim are low operating costs in comparison to other power sources, a long operating life for reactors, and high load factors that enable the investment costs of nuclear power plants to be spread over many kWh, thereby reducing the fixed costs per unit of energy produced. 

But a combination of rising competition and, particularly in France and Japan, rising maintenance costs and outages, have put operating reactors under pressure. In the US, inexpensive natural gas from fracking has been a big factor. There is also pressure from paired solar and storage, where declining costs and higher load factors from the battery firming has been increasingly competitive. 

Market transitions are a standard part of economic growth and resiliency: innumerable facilities shut down temporarily or permanently when changing market conditions render their products too expensive or no longer desired by consumers. Permanent shutdowns happen routinely, and rarely is this because the facility is no longer physically able to produce its product. Indeed, those closures are not viewed as “premature” but rather as the normal functioning of market forces, retiring obsolete assets to make way for competitive new ones.

Nuclear plant closures have been framed entirely differently. Arguing that plant closures would drive up carbon emissions and that their product, labelled “low-carbon, reliable power”, was not being properly valued by the market, the industry has tagged the closures as premature, and has lobbied for—and increasingly often successfully obtained—subsidies to remain in operation. Within the United States, operating subsidies at the state level are estimated to exceed $15 billion by 2030, with new and large supports at the federal level as well. In France, poor economics led to the renationalization of EDF in a transaction finalized in June 2023. French taxpayers will now be enlisted to support reactor refurbishment and operation, as well as the construction of new facilities. In Belgium, subsidies are being directed to restart two reactors and the state has capped the nuclear waste liabilities of utility Engie. And in Japan, a large number of reactors remain closed since the Fukushima accident in March 2011 and the government plans to provide subsidies to accelerate reopenings.

These and similar policies around the world have slowed the pace of reactor exits on the grounds that the reactors provide a short-term bridge of low carbon power and should be protected. Note that a similar outcome -- likely including life extensions for many existing reactors -- would have been achieved by countries pricing greenhouse gas emissions. However, unlike the earmarked subsidies for nuclear, carbon pricing would have put the cost of emissions on polluters and allowed any sector able to provide low-carbon economic services (including, but not limited to electricity) to compete on an equal playing field.

While operating subsidies will keep units open longer, the mean age of reactor fleets outside of China continues to climb: 42.1 years in the US, 37.6 years in France; 29.4 years in Russia. China's mean reactor age is 9.3. (WNISR 2023: 68). Even with subsidies and license extensions, these older units will continue to close over time, and for nuclear to make a material contribution to global decarbonization, there will need to be a large and sustained set of new reactors coming online. 

Nuclear newbuild has become less competitive over time; SMRs seem unlikely to solve this

Estimates of the cost of newbuild reactors are often presented as Overnight Capital Costs (OCC), where the costs of financing, delay, operations and grid connections are ignored; or as a Levelized Cost of Energy (LCOE) which incorporates many of the factors missing from OCC metrics. The OCC is simpler to do, though because construction delays and finance costs are central to the delivered cost of nuclear, it is not a very robust metric for the sector. In the WNISR we reviewed existing OCC and LCOE estimates from a range of studies. Even with the OCC, estimates varied by more than a factor of three across countries. OCC costs per kW for SMRs were also significantly above those for LWRs, highlighting one of the central challenges SMRs face in gaining market share even if NOAK gains are realized. Data availability and cost of capital assumptions varied across assessments. 

The graph below was developed by the IEA in 2020 to show the sensitivity of LCOE estimates to different assumptions on the cost of capital. The lines indicate median values; the shaded area is the 50% central region (20% central region for renewables). The vertical bars on the left chart have been added to show more recent estimates both by IEA and within Lazard's annual review of LCOE trends. 

At very low discount rates, nuclear is highly competitive. This visually illustrates why so many nuclear subsidies focus on shifting the cost and risks of finance from developers onto the state, taxpayers, or customers. However, “shifting the risk does not magically reduce the financing cost; the government’s cost-of-capital is not necessarily less than [that of] private investors.”  Instead, it often means that the government entity is providing a larger credit subsidy to the riskier beneficiary, not that risks are somehow more effectively managed. Nuclear begins to be out-competed by gas at discount rates of around 5 percent/year. At the upper range of a 20 percent/year real cost of capital, nuclear is by far the most expensive, and its median LCOE has jumped five-fold relative to the resource’s lower bound cost. While 20 percent real may seem an excessively high discount rate, target hurdle rates for high-risk venture capital and private equity (a source of capital for some of the new SMR funding) are often around this level.

A few other points are worth noting. First, IEA's estimates assume NOAK gains for nuclear and some price ($30/t) on carbon for coal and gas. Both benefit nuclear's competitive position. Second, the more recent estimates of nuclear LCOEs have been moving up sharply relative to 2020 and earlier. Using these newer estimates, nuclear is not competitive even within the central case discount rates of 7-9%. Third, the Lazard estimate for the US is markedly higher than estimates coming out of the IEA. While Lazard's estimate is based on a smaller sample set (the Vogtle reactors in the US), it also reflects actual rather than projected costs. A meta analysis of 88 reactor projects across the world found actual costs to be much higher than the projected ones, and construction times much longer. 

While most scenarios show nuclear as more expensive than renewables (and the LCOE does a much better job then the OCC in capturing the economic implications of both delayed openings on nuclear and lower load factors on renewables), comparisons with renewables plus firming provide better metrics. Nuclear is starting to be out-competed there as well. Finally, a market-based view of project risk would likely ascribe a higher, and possibly significantly higher, discount rate for nuclear than for the other energy pathways shown. This would worsen the competitive position of nuclear relative to all of its competitors. Despite much effort, we were not able to identify any market-based estimate for the cost of capital of newbuild nuclear. Every project had significant government intervention. 

Lower nuclear LCOEs in China, Russia, South Korea, and a few other countries have been of great interest, and can be seen for China and India in the chart below. Lower cost labor in China and South Korea has been flagged as one source of advantage, as has been better construction management approaches in a number of the lower-cost countries. However, limited data availability has prevented full estimates of LCOEs in many countries by disinterested parties. This is an area of focus that I hope can part of the next WNISR. But given the uncertainties, and full state ownership of the entire fuel cycle in China and Russia, direct comparisons should be done with caution. Subsidies within state-owned enterprises are often both large and quite hard to see and quantify.

Within the low-cost countries, it is also important not to evaluate these competitive advantages in isolation. Whatever its cause (including large state subsidies), the cost advantage also applies at least equally to other forms of energy as well. For example, Chinese wind and solar were well below the cost of Chinese nuclear on a levelized cost/MWh basis, “so China invested at least as much in renewables in 2020 as it had invested cumulatively in nuclear power during 2008–20, adding half the world’s 2020 new renewable capacity and 80% of the global increase over 2019’s.” .

Figure 1

Sources: NEA/IEA 2020; IEA 2021-23; Lazard 2023 
 

Government subsidies to nuclear have always been large, but they are getting bigger still

Functioning markets allow complicated trade-offs to be made more seamlessly. In cases where there are externalities such as carbon emissions, putting a price on them can address the problem over time. That approach also allows the full range of possible solutions to come to the fore: new generation, efficiency, load shifting, power storage, and so forth. With subsidies, political lobbying or governmental preferences become much more important determinants of where limited public resources are spent, for how long, and which solutions "win."

Table 1 provides an overall picture of the role of the state in the nuclear energy pathway. Each element is discussed in much more detail in the Economics and Finance chapter. But it is evident even within the Table how significant a role state ownership and support plays in the rise of China and Russia within the nuclear sector; and in key steps of the fuel chain, including uranium mining, conversion, enrichment, facility decommissioning, nuclear waste management, and accident liability. Also important is just how many different ways governments have tried to subsidize the cost to finance new plants. Because there are many ways to decarbonize the world, directing so much support by government fiat creates competitive problems that likely result in decarbonization that is smaller in scale, slower, and more expensive that what could be achieved by pricing carbon. 

Table 1
Large and Growing Role of the State in all Parts of the Nuclear Fuel Chain

Source: Compiled from WNISR 2023

New markets for nuclear will be challenging and often compete with existing electricity customers

Frequently-mentioned areas of future growth for nuclear include production of hydrogen, water desalination, high temperature heat, and power for industrial production, and dedicated use for remote locations or high-demand applications such as data centers. These applications require cost-competitive power. Unless newbuild nuclear can achieve large cost reductions, new reactors are not likely to drive growth in these other areas. 

Rather, the most likely way to support these new markets will be from the existing set of operating reactors. Efforts to use surplus power from existing nuclear to support these markets is attractive since the cost of power from existing reactors is lower, and there is excess supply during some periods of the day. However, because the industrial users require highly reliable deliveries to keep production orderly, efficient, and competitive, either a dedicated reactor or a 24/7 slice of reactor production would be needed. This would put these other uses in competition with current grid users for low-carbon electricity rather than increasing the overall supply. Particularly where market diversions are driven by government subsidy (perhaps the case with hydrogen in the U.S.) rather than economic value, both system costs and carbon emissions could rise.

Table 2

Source: Compiled from WNISR 2023

Nuclear economics remain underwhelming, but the creative ways the industry pursues to shift risks onto others and to seek new subsidies for themselves continue unabated.  Here's a run-down of a few recent developments.

1)  NRC approves sale of closed Pilgrim nuclear reactor to Holtec.  After studying the deal, NRC decided Holtec can do this, even though they've never done it before and are trying to do it for the first time in lots of places at once.  Absent adverse rulings by commissioners in the next couple of days, the decision will become final.  Or mostly, sort of, final.  Holtec gets the closed contaminated reactor, the land, and more than $1 billion in the plant's nuclear decommissioning trust fund.  That money will be used to pay for decommissioning -- much of it conducted using staff, facilities, and resources related to the plant's new owner or affiliated parties. The NRC decision also gives Holtec an exemption to use the decommissioning trust fund to pay to manage the spent fuel and other site restoration activities.  What could possibly go wrong?

Not surprisingly, Holtec's spokesperson Joe Delmarin concluded that "the transfer of Pilgrim to Holtec for prompt decommissioning is in the best interests of the town of Plymouth and surrounding communities, the nearly 270 people from the region who work at Pilgrim, and the Commonwealth." A bit early to tell, in my view.  And the Commonwealth doesn't seem to agree either. 

Detailed and well-structured petitions to intervene by both citizen's group Pilgrim Watch and the Massachusetts Attorney General seem largely to have been ignored. Though, here the "mostly, sort of" framing comes into play, as the NRC writes in its decision that:

These requests are pending before the Commission. The hearing, if granted, will not be completed prior to approval of the license transfer application. The order approving the transfer will include a condition that the NRC staff’s approval of the license transfer is subject to the Commission’s authority to rescind, modify or condition the approved transfer based on the outcome of any post-effectiveness hearing on the license transfer application.

Mary Lampert, director of Pilgrim Watch, puts little stake in these caveats, however.  And there is no indication in the current license transfer approval that the NRC is ensuring backup funding from the current owner should Holtec run out of money.  Since the new owner has structured the deal using poorly capitalized stand-alone limited liability companies, such prudence would be warranted.

For more on Holtec and the potential problems on their closed reactor buying spree, see a deep-dive on the issue I did in an earlier blog post.

2)  Faster decommissioning means moving lots of radioactive waste somewhere; and those places don't seem happy to get it.  The Permian Basin is undergoing and oil and gas boom.  It is also being targeted for "interim" storage of a variety of nuclear wastes.  Not everybody is happy about this.  The Texas facility would be run by Interim Storage Partners, a partnership of Waste Control Specialists and Orano USA.  Orano, formerly Areva Nuclear Materials, is involved with the rapid decommissioning of Vermont Yankee -- which is not a Holtec project but using a similar approach. 

Holtec's go-to holding ground for nuclear waste from its projects would be in southeastern New Mexico.  Holtec's facility is also tagged as "interim," though few seem to believe that.  "Interim," after all, is a fairly flexible term:  with a radioactivity window of thousands of years, one can call a facility interim with a straight face, knowing full well stuff will be sitting there for centuries. Opponents to Holtec's waste facility are many, and include New Mexico's governor. 

How rejection, long delays, or much higher costs in the disposal sites affect the economics of Holtec's ability to carry out the decommissioning at the reactors it now owns without running out of money will be interesting to see.

3)  Shellenberger:  summer is for nukes.  Most people think beaches and gin and tonics during summer.  For Michael Shellenberger, winter, spring, summer or fall doesn't matter:  nuclear power is always on his mind.  He is a dogged advocate of a nuclear-led solution to climate change.  And while I often admire his dedication, he sometimes looks only on the bright side of life, glossing over important and material limitations with his favored nuclear solutions in the process.  This seems to have been the case in his promotion of nuclear reliability in summer as a big selling point of the technology in a column he wrote last summer in Forbes, and that I recently re-read.

He rightly pointed out that peak electricity demand is often during summer, and shortages are common.  His specific examples focus on plant outages, a lack of wind during periods of high heat, and solar panels' reduced efficiency at very high temperatures as factors that can trigger regional power supply deficits, and surging peak prices.  He argues that particularly in summer, nuclear is central to rescuing the grid, pointing to South Korea, Taiwan, and Japan as examples where reactors, including restarting closed ones, were integral to meet summer demand in recent years. 

And in his own state of California, Shellenberger references the National Weather Service telling people to go somewhere else if they lose power.  He also argues that power is much more expensive once reactors close.  This last point raises once again a core question I've been trying to get a good answer to for years:  if nuclear really (and not just in industry PR packs) helps keep energy costs so much lower for all users, why is it that the industry can't figure out a business model that keeps operating reactors solvent without crying for bailouts in state after state? 

But that is a question for another day.  Back to Shellenberger's nuclear summer:  in pointing out a handful of countries relying on nuclear to meet summer peaks, it is hard to believe that somebody as prolific in this area as he is would be unaware of the quite significant counter-case to his core argument.  Far from always being the go-to resource to beat the heat, reactors in many parts of the world have been shuttered during summer months because they need massive amounts of cooling water.  And the problem appears to be getting worse.

High temperatures can reduce available intake flows and increase the ambient temperatures in receiving waters.  The high temps already stress wildlife even before the water is further heated by doing reactor-cooling duty.  At a certain point, the reactors are no longer able or allowed to pull water or to discharge extra heat.  Depending on the capacity of the receiving waters, reactors may need to be fully shut down; in other cases they must ramp down to a lower production level.

Ironically, one of usually-ignored subsidies to reactors (at least in the US, though likely in other countries as well) is free cooling water.  Not only free, but also generally senior and firm water rights, sometimes at the expense of other users of that same water body.  In addition to reducing the delivered cost of nuclear electricity, this subsidy also allowed reactor owners to largely ignore cooling efficiency when they designed and built the current generation of reactors.  Had the reactors been forced to pay for their water rights, they likely would have adopted much more water-efficient cooling techniques, and as a result been less likely to face forced closures during periods of high heat now.  

Here are a few links that highlight a much more complicated picture on summer nukes than the one Shellenberger painted.  The first is an overview of the issue and how it will get worse with rising global temperatures by Christina Chen at NRDC.  An earlier paper by Linnerud, Mideska and Eskelund looks at how higher temperatures in ambient cooling water can reduce reactor efficiency.  Plant closures due to cooling water issues include France, Sweden and Finland (2018); and France and Germany (2019).  Heat-related curtailments, discharge heat waivers, and shutdowns have been common in earlier years, including in the United States (2003, 2012, and probably other years as well were I to keep searching).  US nuclear power curtailments have been rising over time, along with global average temperatures.  Interestingly, I couldn't find examples on nuclear power curtailment during hot weather outside of the US and Western Europe.  This either means that the reactors in all of the other countries have much better proximity to high-cooling capacity receiving waters; that they have weaker regulations in terms of heat discharge; or that there are curtailments and closures, but they are not being reported.

4)  NuSubsidies I - fast breeder reactors.  Federally funded.  High costs, increased proliferation risks.  I'm sure it will go better than last time.

5)  NuSubsidies II - advanced reactors.  Forty-year power purchase agreements allowed (max of ten years for other technologies); can be at above market rates in the Nuclear Energy Leadership Act (NELA), reintroduced in May.  Apparently targeted at small modular reactors, though the bill language appears flexible enough to apply to derivative generations of current, larger reactors as well so long as they meet the NRC licensing window set out in the proposed legislation.  Thankfully, this is still proposal, not actual law. 

6)  And the band plays on: more delays and cost escalation for the Vogtle reactors.  Not surprising at this point to see the Vogtle monster continue to burn cash, though the never-ending cost increases are a bitter pill for ratepayers on the hook to buy the power at the end.  If the project goes bankrupt (as it still could), the big losers shift from ratepayers to federal taxpayers.  As of March 2019, the Department of Energy boosted the size of taxpayer loan guarantees to $12 billion.  Some day, Congress or the DOE Office of Inspector General will finally do a real investigation on how this fiasco emerged.  That investigation may well include a look into the use of private emails for public business.

Even before financing costs, the two-reactor set is expected to exceed $17 billion in cost.  More delays are also expected, and when one has a very large investment for which revenues keep getting pushed further into the future, the financing costs will continue to escalate quickly.  The end of the complex portions of the construction effort are not near either: 

Already, the remaining work is expected to be 2.5 times more dollar-intensive than the construction finished thus far. Workers have completed 77 percent of the project at a cost of $9.86 billion. The remaining 23 percent is budgeted to cost $7.243 billion, assuming it does not run over. 

This summary, from two weeks ago in a Greentech Media article by Julian Spector, ends with a quote from Jessica Lovering, director of energy at The Breakthrough Institute, a group that has been pushing nuclear as a central (often the central) solution to climate since its founding more than 15 years ago. Lovering remarks "Ultimately, we need to move away from nuclear power plants as these big infrastructure projects with lots of people doing artisanal craftsmanship and move toward factory fabrication."

I've never heard the term "artisanal craftsmanship" applied to massive nuclear projects before.  But I kind of like it.  It makes a huge, expensive, and too often poorly-run engineering undertaking sound like a quaint craft fair. 

Yes, reactors, or large one-off construction projects in general, are prone to a certain set of problems that drive costs up.  But it is also true that for 60 years, cost reductions in nuclear power came through economies of scale to spread massive costs over a massive number of kWh.  Indeed, these assumptions on where economic gains were to come from continued to play a central role in some of the core research by MIT and the University of Chicago that underpinned the planned nuclear renaissance in the early 2000s.  These analyses suggested that while your First-of-a-Kind (FOAK) unit might be expensive (though their projections were way lower even on FOAK than what has emerged), the "nth of a kind" reactor would be cheaper than competing forms of baseload power. 

Standardization and production lines, Lovering's new model, really seem to apply only to the small modular units.  The standardization could lead to lower unit costs of production; but the scale of savings seem far too small to really bring LCOE in line with alternatives.  Indeed, high cost seems likely to remain a problem even with the SMRs for quite some time to come.

How long the period of high costs will last remains a critical variable: in the end, SMRs are competing less against wind or solar, and more against the power storage that converts intermittent resources into generation just as reliable as nuclear for the vast majority of applications.  Could SMRs ramp up their learning curves on both technology and production quickly enough to be relevant in dealing with climate change over the next 10-15 years?  Bill Gates certainly believes so.  But I view it as a long-shot, as the costs of power storage continues to fall more rapidly than expected and the market demand for batteries remains enormous, driving massive research and experimentation on all elements of the storage product cycle.  Four years after I wrote this this, power costs are falling faster than predicted, and nuclear costs continue to rise.  My bet is still on batteries to win.