For example, a mixture of 7% plutonium and 93% natural uranium
reacts similarly, although not identically, to LEU fuel. MOX usually
consists of two phases, UO2 and PuO2, and/or a single phase solid solution (U,Pu)O2. The content of PuO2 may vary from 1.5 wt.% to 25–30 wt.% depending on the type of nuclear reactor.
One attraction of MOX fuel is that it is a way of utilizing surplus weapons-grade plutonium, an alternative to storage of surplus plutonium, which would need to be secured against the risk of theft for use in nuclear weapons. On the other hand, some studies warned that normalising the global commercial use of MOX fuel and the associated expansion of nuclear reprocessing will increase, rather than reduce, the risk of nuclear proliferation, by encouraging increased separation of plutonium from spent fuel in the civil nuclear fuel cycle.
Normally, with the fuel being changed every three years or so, most
of the plutonium-239 is "burned" in the reactor. It behaves like
uranium-235, with a slightly higher cross section for fission, and its fission releases a similar amount of energy. Typically, about one percent of the spent fuel
discharged from a reactor is plutonium, and some two-thirds of the
plutonium is plutonium-239. Worldwide, almost 100 tonnes of plutonium in
spent fuel arises each year. A single recycling of plutonium increases
the energy derived from the original uranium by some 12%, and if the
uranium-235 is also recycled by re-enrichment, this becomes about 20%. With additional recycling the percentage of fissile (usually meaning odd-neutron number) nuclides in the mix decreases and even-neutron number, neutron-absorbing nuclides increase, requiring the total plutonium and/or enriched uranium percentage to be increased. Today in thermal reactors plutonium is only recycled once as MOX fuel; spent MOX fuel, with a high proportion of minor actinides and even plutonium isotopes, is stored as waste.
Existing nuclear reactors
must be re-licensed before MOX fuel can be introduced because using it
changes the operating characteristics of a reactor, and the plant must
be designed or adapted slightly to take it; for example, more control rods
are needed. Often only a third to half of the fuel load is switched to
MOX, but for more than 50% MOX loading, significant changes are
necessary and a reactor needs to be designed accordingly. The System 80 reactor design, notably deployed at the U.S. Palo Verde Nuclear Generating Station near Phoenix, Arizona,
was designed for 100% MOX core compatibility, but so far has always
operated on fresh low enriched uranium. In theory, the three Palo Verde
reactors could use the MOX arising from seven conventionally fueled
reactors each year and would no longer require fresh uranium fuel.
The content of un-burnt plutonium in spent MOX fuel
from thermal reactors is significant – greater than 50% of the initial
plutonium loading. However, during the burning of MOX the ratio of
fissile (odd numbered) isotopes to non-fissile (even) drops from around
65% to 20%, depending on burn up. This makes any attempt to recover the
fissile isotopes difficult and any bulk Pu recovered would require such a
high fraction of Pu in any second generation MOX that it would be
impractical. This means that such a spent fuel would be difficult to
reprocess for further reuse (burning) of plutonium. Regular reprocessing
of biphasic spent MOX is difficult because of the low solubility of PuO2 in nitric acid.
As of 2015, the only commercial demonstration of twice recycled, high burnup fuel occurred in the Phénix fast reactor.
Current applications
A used MOX, which has 63 GW days (thermal) of burnup and has been examined with a scanning electron microscope
using electron microprobe attachment. The lighter the pixel in the
right hand side the higher the plutonium content of the material at that
spot
Reprocessing of commercial nuclear fuel to make MOX is done in the United Kingdom and France, and to a lesser extent in Russia, India and Japan. China plans to develop fast breeder reactors
and reprocessing. Reprocessing of spent commercial-reactor nuclear fuel
is not permitted in the United States due to nonproliferation
considerations. All of these nations have long had nuclear weapons from
military-focused research reactor fuels except Japan.
The United States was building a MOX plant at the Savannah River Site in South Carolina. Although the Tennessee Valley Authority (TVA) and Duke Energy expressed interest in using MOX reactor fuel from the conversion of weapons-grade plutonium,
TVA (currently the most likely customer) said in April 2011 that it
would delay a decision until it could see how MOX fuel performed in the
nuclear accident at Fukushima Daiichi.
In May 2018, the Department of Energy reported that the plant would
require another $48 billion to complete, on top of the $7.6 billion
already spent. Construction was cancelled.
Thermal reactors
About 30 thermal reactors in Europe (Belgium, the Netherlands, Switzerland, Germany and France) are using MOX
and an additional 20 have been licensed to do so. Most reactors use it
as about one third of their core, but some will accept up to 50% MOX
assemblies. In France, EDF aims to have all its 900 MWe series of
reactors running with at least one-third MOX. Japan aimed to have one
third of its reactors using MOX by 2010, and has approved construction
of a new reactor with a complete fuel loading of MOX. Of the total
nuclear fuel used today, MOX provides 2%.
Licensing and safety issues of using MOX fuel include:
As plutonium isotopes absorb more neutrons than uranium fuels, reactor control systems may need modification.
MOX fuel tends to run hotter because of lower thermal conductivity, which may be an issue in some reactor designs.
Fission gas release in MOX fuel assemblies may limit the maximum burn-up time of MOX fuel.
About 30% of the plutonium originally loaded into MOX fuel is
consumed by use in a thermal reactor. In theory, if one third of the
core fuel load is MOX and two-thirds uranium fuel, there is zero net
gain of plutonium in the spent fuel,
and the cycle could be repeated; however, there remains multiple
difficulties in reprocessing spent MOX fuel. As of 2010, plutonium is
only recycled once in thermal reactors, and spent MOX fuel is separated
from the rest of the spent fuel to be stored as waste.
All plutonium isotopes are either fissile or fertile, although plutonium-242 needs to absorb 3 neutrons before becoming fissile curium-245; in thermal reactors isotopic degradation limits the plutonium recycle potential. About 1% of spent nuclear fuel from current LWRs is plutonium, with approximate isotopic composition 52% 239 94Pu , 24% 240 94Pu , 15% 241 94Pu , 6% 242 94Pu and 2% 238 94Pu when the fuel is first removed from the reactor.
Fast reactors
Because the fission-to-capture ratio of neutron cross-section with high energy or fast neutrons changes to favour fission for almost all of the actinides, including 238 92U , fast reactors can use all of them for fuel. All actinides, including TRU or transuranium actinides can undergo neutron induced fission with unmoderated or fast neutrons. A fast reactor
is more efficient for using plutonium and higher actinides as fuel.
Depending on how the reactor is fueled it can either be used as a
plutonium breeder or burner.
These fast reactors are better suited for the transmutation
of other actinides than thermal reactors. Because thermal reactors use
slow or moderated neutrons, the actinides that are not fissionable with
thermal neutrons tend to absorb the neutrons instead of fissioning. This
leads to buildup of heavier actinides and lowers the number of thermal
neutrons available to continue the chain reaction.
Fabrication
The
first step is separating the plutonium from the remaining uranium
(about 96% of the spent fuel) and the fission products with other wastes
(together about 3%). This is undertaken at a nuclear reprocessing plant.
Dry mixing
MOX fuel can be made by grinding together uranium oxide (UO2) and plutonium oxide (PuO2)
before the mixed oxide is pressed into pellets, but this process has
the disadvantage of forming much radioactive dust. MOX fuel, consisting
of 7% plutonium mixed with depleted uranium, is equivalent to uranium oxide fuel enriched to about 4.5% 235 92U , assuming that the plutonium has about 60–65% 239 94Pu . If weapons-grade plutonium were used (>90% 239 94Pu ), only about 5% plutonium would be needed in the mix.
Coprecipitation
A mixture of uranyl nitrate and plutonium nitrate in nitric acid is converted by treatment with a base such as ammonia to form a mixture of ammonium diuranate and plutonium hydroxide. After heating in a mixture of 5% hydrogen and 95% argon will form a mixture of uranium dioxide and plutonium dioxide. Using a base, the resulting powder can be run through a press and converted into green colored pellets. The green pellet can then be sintered into mixed uranium and plutonium oxide pellet. While this second type of fuel is more homogenous on the microscopic scale (scanning electron microscope) it is possible to see plutonium rich areas and plutonium poor areas. It can be helpful to think of the solid as being like a salami (more than one solid material present in the pellet).
Americium content
Plutonium
from reprocessed fuel is usually fabricated into MOX within less than
five years of its production to avoid problems resulting from impurities
produced by the decay of short-lived isotopes of plutonium. In particular, plutonium-241 decays to americium-241 with a 14-year half-life. Because americium-241 is a gamma ray emitter, its presence is a potential occupational health hazard. It is possible, however, to remove the americium
from the plutonium by a chemical separation process. Even under the
worst conditions, the americium/plutonium mixture is less radioactive
than a spent-fuel dissolution liquor, so it should be relatively
straightforward to recover the plutonium by PUREX or another aqueous reprocessing method.
Curium content
It is possible that both americium and curium
could be added to a U/Pu MOX fuel before it is loaded into a fast
reactor. This is one means of transmutation. Work with curium is much
harder than americium because curium is a neutron emitter, the MOX
production line would need to be shielded with both lead and water to protect the workers.
Also, the neutron irradiation of curium generates the higher actinides, such as californium, which increase the neutron dose associated with the used nuclear fuel;
this has the potential to pollute the fuel cycle with strong neutron
emitters. As a result, it is likely that curium will be excluded from
most MOX fuels.
Thorium MOX
MOX fuel containing thorium and plutonium oxides is also being tested. According to a Norwegian study, "the coolant void reactivity of the thorium-plutonium fuel is negative for plutonium contents up to 21%, whereas the transition lies at 16% for MOX fuel." The authors concluded, "Thorium-plutonium fuel seems to offer some advantages over MOX fuel with regards to control rod and boron worths, CVR and plutonium consumption."
EDF
has said its third-generation EPR Flamanville 3 project (seen here in
2010) will be delayed until 2018, due to "both structural and economic
reasons," and the project's total cost has climbed to EUR 11 billion in
2012.
On 29 June 2019, it was announced that the start-up was once again
being pushed back, making it unlikely it could be started before the end
of 2022. In July 2020, the French Court of Audit finalised an
eighteen-month in-depth analysis of the project, concluding that the
total estimated cost reaches up to €19.1 billion which is more than 5
times the original cost estimate. Similarly, the cost of the EPR being
built at Olkiluoto, Finland, has escalated dramatically from €3 billion
to over €12 billion , and the project is well behind schedule.
Originally to commence operation in 2009 and that is now unlikely to be
before 2022. The initial low cost forecasts for these megaprojects exhibited "optimism bias".
New nuclear power plants typically have high capital expenditure
for building the plant. Fuel, operational, and maintenance costs are
relatively small components of the total cost. The long service life and
high capacity factor of nuclear power plants allow sufficient funds for ultimate plant decommissioning and waste storage and management to be accumulated, with little impact on the price per unit of electricity generated. Other groups disagree with these statements. Additionally, measures to mitigate climate change such as a carbon tax or carbon emissions trading, would favor the economics of nuclear power over fossil fuel power. Other groups argue that nuclear power is not the answer to climate change.
Nuclear power construction costs have varied significantly across
the world and in time.
Large and rapid increases in cost occurred during the 1970s, especially
in the United States.
There were no construction starts of nuclear power reactors between 1979
and 2012 in the United States, and since then more new reactor projects
have gone into bankruptcy than have been completed.
Recent cost trends in countries such as Japan and Korea have been very
different, including periods of stability and decline in costs.
In more economically developed countries, a slowdown in
electricity demand growth in recent years has made large-scale power
infrastructure investments difficult. Very large upfront costs and long
project cycles carry large risks, including political decision making
and intervention such as regulatory ratcheting. In Eastern Europe, a number of long-established projects are struggling to find financing, notably Belene in Bulgaria and the additional reactors at Cernavoda in Romania, and some potential backers have pulled out.
Where cheap gas is available and its future supply relatively secure,
this also poses a major problem for clean energy projects. Former Exelon CEO John Rowe
said in 2012 that new nuclear plants in the United States "don't make
any sense right now" and would not be economic as long as gas prices
remain low.
Current bids for new nuclear power plants in China were estimated at between $2800/kW and $3500/kW, as China planned to accelerate its new build program after a pause following the Fukushima disaster.
However, more recent reports indicated that China will fall short of
its targets. While nuclear power in China has been cheaper than solar
and wind power, these are getting cheaper while nuclear power costs are
growing. Moreover, third generation plants are expected to be
considerably more expensive than earlier plants.
Therefore, comparison with other power generation methods is strongly
dependent on assumptions about construction timescales and capital
financing for nuclear plants.
Analysis of the economics of nuclear power must take into account who
bears the risks of future uncertainties. To date all operating nuclear
power plants were developed by state-owned or regulatedutility monopolies
where many of the risks associated with political change and regulatory
ratcheting were borne by consumers rather than suppliers. Many
countries have now liberalized the electricity market
where these risks, and the risk of cheap competition from subsidised
energy sources emerging before capital costs are recovered, are borne by
plant suppliers and operators rather than consumers, which leads to a
significantly different evaluation of the risk of investing in new
nuclear power plants.
Two of the four EPRs under construction (the Olkiluoto Nuclear Power Plant in Finland and Flamanville in France), which are the latest new builds in Europe, are significantly behind schedule and substantially over cost.
Following the 2011 Fukushima Daiichi nuclear disaster, costs are likely
to go up for some types of currently operating and new nuclear power
plants, due to new requirements for on-site spent fuel management and elevated design basis threats.
Overview
Olkiluoto 3 under construction in 2009. It is the first EPR
design, but problems with workmanship and supervision have created
costly delays which led to an inquiry by the Finnish nuclear regulator STUK.
In December 2012, Areva estimated that the full cost of building the
reactor will be about €8.5 billion, or almost three times the original
delivery price of €3 billion.
Although the price of new plants in China is lower than in the Western world John Quiggin, an economics professor, maintains that the main problem with the nuclear option is that it is not economically viable.
Professor of science and technology Ian Lowe has also challenged the economics of nuclear power.
However, nuclear supporters continue to point to the historical success
of nuclear power across the world, and they call for new reactors in
their own countries, including proposed new but largely uncommercialised
designs, as a source of new power.
Nuclear supporters point out that the IPCC climate panel endorses
nuclear technology as a low carbon, mature energy source which should be
nearly quadrupled to help address soaring greenhouse gas emissions.
Some independent reviews keep repeating that nuclear power plants are necessarily very expensive, and anti-nuclear groups frequently produce reports that say the costs of nuclear energy are prohibitively high.
In 2012 in Ontario, Canada, costs for nuclear generation stood at 5.9¢/kWh while hydroelectricity, at 4.3¢/kWh, cost 1.6¢ less than nuclear. By September 2015, the cost of solar in the United States dropped below nuclear generation costs, averaging 5¢/kWh.
Solar costs continued to fall, and by February 2016, the City of Palo
Alto, California, approved a power-purchase agreement (PPA) to purchase
solar electricity for under 3.68¢/kWh,
lower than even hydroelectricity. Utility-scale solar electricity
generation newly contracted by Palo Alto in 2016 costs 2.22¢/kWh less
than electricity from the already-completed Canadian nuclear plants, and
the costs of solar energy generation continue to drop.
However, solar power has very low capacity factors compared to nuclear,
and solar power can only achieve so much market penetration before
(expensive) energy storage and transmission become necessary.
Countries including Russia, India, and China, have continued to
pursue new builds. Globally, around 50 nuclear power plants were under
construction in 20 countries as of April 2020, according to the IAEA. China has 10 reactors under construction. According to the World Nuclear Association, the global trend is for new nuclear power stations coming online to be balanced by the number of old plants being retired.
In the United States, nuclear power faces competition from the low natural gas prices in North America. Former Exelon CEO John Rowe
said in 2012 that new nuclear plants in the United States "don’t make
any sense right now" and won't be economic as long as the natural gas
glut persists. In 2016, Governor of New YorkAndrew Cuomo directed the New York Public Service Commission to consider ratepayer-financed subsidies similar to those for renewable sources to keep nuclear power stations profitable in the competition against natural gas.
A 2019 study by the economic think tank DIW found that nuclear power has not been profitable anywhere in the World.
The study of the economics of nuclear power has found it has never been
financially viable, that most plants have been built while heavily
subsidised by governments, often motivated by military purposes, and
that nuclear power is not a good approach to tackling climate change. It
found, after reviewing trends in nuclear power plant construction since
1951, that the average 1,000MW nuclear power plant would incur an
average economic loss of 4.8 billion euros ($7.7 billion AUD). This has
been refuted by another study.
Capital costs
"The usual rule of thumb for nuclear power is that about two thirds
of the generation cost is accounted for by fixed costs, the main ones
being the cost of paying interest on the loans and repaying the
capital..."
Capital cost, the building and financing of nuclear power plants,
represents a large percentage of the cost of nuclear electricity. In
2014, the US Energy Information Administration estimated that for new
nuclear plants going online in 2019, capital costs will make up 74% of
the levelized cost of electricity; higher than the capital percentages
for fossil-fuel power plants (63% for coal, 22% for natural gas), and
lower than the capital percentages for some other nonfossil-fuel sources
(80% for wind, 88% for solar PV).
Areva, the French nuclear plant operator, offers that 70% of the
cost of a kWh of nuclear electricity is accounted for by the fixed costs
from the construction process.
Some analysts argue (for example Steve Thomas, Professor of Energy
Studies at the University of Greenwich in the UK, quoted in the book The Doomsday Machine
by Martin Cohen and Andrew McKillop) that what is often not appreciated
in debates about the economics of nuclear power is that the cost of
equity, that is companies using their own money to pay for new plants,
is generally higher than the cost of debt.
Another advantage of borrowing may be that "once large loans have been
arranged at low interest rates – perhaps with government support – the
money can then be lent out at higher rates of return".
"One of the big problems with nuclear power is the enormous upfront
cost. These reactors are extremely expensive to build. While the returns
may be very great, they're also very slow. It can sometimes take
decades to recoup initial costs. Since many investors have a short
attention span, they don't like to wait that long for their investment
to pay off."
Because of the large capital costs for the initial nuclear power
plants built as part of a sustained build program, and the relatively
long construction period before revenue is returned, servicing the capital costs of first few nuclear power plants can be the most important factor determining the economic competitiveness of nuclear energy. The investment can contribute about 70% to 80% of the costs of electricity. Timothy Stone,
businessman and nuclear expert, stated in 2017 "It has long been
recognised that the only two numbers which matter in [new] nuclear power
are the capital cost and the cost of capital." The discount rate chosen to cost a nuclear power plant's capital over its lifetime is arguably the most sensitive parameter to overall costs.
Because of the long life of new nuclear power plants, most of the value
of a new nuclear power plant is created for the benefit of future
generations.
The recent liberalization of the electricity market in many countries has made the economics of nuclear power generation less attractive, and no new nuclear power plants have been built in a liberalized electricity market.
Previously a monopolistic provider could guarantee output requirements
decades into the future. Private generating companies now have to accept
shorter output contracts and the risks of future lower-cost
competition, so they desire a shorter return on investment period. This
favours generation plant types with lower capital costs or high
subsidies, even if associated fuel costs are higher. A further difficulty is that due to the large sunk costs
but unpredictable future income from the liberalized electricity
market, private capital is unlikely to be available on favourable terms,
which is particularly significant for nuclear as it is
capital-intensive.
Industry consensus is that a 5% discount rate is appropriate for plants
operating in a regulated utility environment where revenues are
guaranteed by captive markets, and 10% discount rate is appropriate for a
competitive deregulated or merchant plant environment;
however the independent MIT study (2003) which used a more
sophisticated finance model distinguishing equity and debt capital had a
higher 11.5% average discount rate.
As states are declining to finance nuclear power plants, the
sector is now much more reliant on the commercial banking sector.
According to research done by Dutch banking research group Profundo,
commissioned by BankTrack, in 2008 private banks invested almost €176 billion in the nuclear sector. Champions were BNP Paribas, with more than €13,5 billion in nuclear investments and Citigroup and Barclays
on par with both over €11,4 billion in investments. Profundo added up
investments in eighty companies in over 800 financial relationships with
124 banks in the following sectors: construction, electricity, mining, the nuclear fuel cycle and "other".
A 2016 study argued that while costs did increase in the past for
reactors built in the past, this does not necessarily mean there is an
inherent trend of cost escalation with nuclear power, as prior studies
tended to examine a relatively small share of reactors built and that a
full analysis shows that cost trends for reactors varied substantially
by country and era.
Cost overruns
Construction
delays can add significantly to the cost of a plant. Because a power
plant does not earn income and currencies can inflate during
construction, longer construction times translate directly into higher
finance charges. Modern nuclear power plants are planned for
construction in five years or less (42 months for CANDU ACR-1000, 60 months from order to operation for an AP1000, 48 months from first concrete to operation for an EPR and 45 months for an ESBWR) as opposed to over a decade for some previous plants. However, despite Japanese success with ABWRs, two of the four EPRs under construction (in Finland and France) are significantly behind schedule.
In the United States many new regulations were put in place in the years before and again immediately after the Three Mile Island accident's partial meltdown, resulting in plant startup delays of many years. The NRC has new regulations in place now,
and the next plants will have NRC Final Design Approval before the
customer buys them, and a Combined Construction and Operating License
will be issued before construction starts, guaranteeing that if the
plant is built as designed then it will be allowed to operate—thus
avoiding lengthy hearings after completion.
In Japan and France,
construction costs and delays are significantly diminished because of
streamlined government licensing and certification procedures. In
France, one model of reactor was type-certified, using a safety engineering
process similar to the process used to certify aircraft models for
safety. That is, rather than licensing individual reactors, the
regulatory agency certified a particular design and its construction
process to produce safe reactors. U.S. law permits type-licensing of
reactors, a process which is being used on the AP1000 and the ESBWR.
In Canada, cost overruns for the Darlington Nuclear Generating Station,
largely due to delays and policy changes, are often cited by opponents
of new reactors. Construction started in 1981 at an estimated cost of
$7.4 Billion 1993-adjusted CAD, and finished in 1993 at a cost of $14.5
billion. 70% of the price increase was due to interest charges incurred
due to delays imposed to postpone units 3 and 4, 46% inflation over a
4-year period and other changes in financial policy.
No new nuclear reactor has since been built in Canada, although a few
have been and are undergoing refurbishment and environment assessment is
complete for 4 new generation stations at Darlington with the Ontario
government committed in keeping a nuclear base load of 50% or around
10GW.
In the United Kingdom and the United States cost overruns on
nuclear plants contributed to the bankruptcies of several utility
companies. In the United States these losses helped usher in energy
deregulation in the mid-1990s that saw rising electricity rates and
power blackouts in California. When the UK began privatizing utilities,
its nuclear reactors "were so unprofitable they could not be sold."
Eventually in 1996, the government gave them away. But the company that
took them over, British Energy, had to be bailed out in 2004 to the
extent of 3.4 billion pounds.
Operating costs
In
general, coal and nuclear plants have the same types of operating costs
(operations and maintenance plus fuel costs). However, nuclear has
lower fuel costs but higher operating and maintenance costs.
Fuel costs
Nuclear plants require fissile fuel. Generally, the fuel used is uranium, although other materials may be used. In 2005, prices on the world market for uranium averaged US$20/lb (US$44.09/kg). On 2007-04-19, prices reached US$113/lb (US$249.12/kg). On 2008-07-02, the price had dropped to $59/lb.
Fuel costs account for about 28% of a nuclear plant's operating expenses.
As of 2013, half the cost of reactor fuel was taken up by enrichment
and fabrication, so that the cost of the uranium concentrate raw
material was 14 percent of operating costs.
Doubling the price of uranium would add about 10% to the cost of
electricity produced in existing nuclear plants, and about half that
much to the cost of electricity in future power plants.
The cost of raw uranium contributes about $0.0015/kWh to the cost of
nuclear electricity, while in breeder reactors the uranium cost falls to
$0.000015/kWh.
As of 2008, mining activity was growing rapidly, especially from
smaller companies, but putting a uranium deposit into production takes
10 years or more.
The world's present measured resources of uranium, economically
recoverable at a price of US$130/kg according to the industry groups Organisation for Economic Co-operation and Development (OECD), Nuclear Energy Agency (NEA) and International Atomic Energy Agency (IAEA), are enough to last for "at least a century" at current consumption rates.
According to the World Nuclear Association,
"the world's present measured resources of uranium (5.7 Mt) in the cost
category less than three times present spot prices and used only in
conventional reactors, are enough to last for about 90 years. This
represents a higher level of assured resources than is normal for most
minerals. Further exploration and higher prices will certainly, on the
basis of present geological knowledge, yield further resources as
present ones are used up." The amount of uranium present in all
currently known conventional reserves alone (excluding the huge
quantities of currently-uneconomical uranium present in "unconventional"
reserves such as phosphate/phosphorite deposits, seawater, and other
sources) is enough to last over 200 years at current consumption rates.
Fuel efficiency in conventional reactors has increased over time.
Additionally, since 2000, 12–15% of world uranium requirements have been
met by the dilution of highly enriched weapons-grade uranium from the
decommissioning of nuclear weapons and related military stockpiles with
depleted uranium, natural uranium, or partially-enriched uranium sources
to produce low-enriched uranium for use in commercial power reactors.
Similar efforts have been utilizing weapons-grade plutonium to produce
mixed oxide (MOX) fuel, which is also produced from reprocessing used
fuel. Other components of used fuel are currently less commonly
utilized, but have a substantial capacity for reuse, especially so in
next-generation fast neutron reactors. Over 35 European reactors are
licensed to use MOX fuel, as well as Russian and American nuclear
plants. Reprocessing of used fuel increases utilization by approximately
30%, while the widespread use of fast breeder reactors would allow for
an increase of "50-fold or more" in utilization.
Waste disposal costs
All nuclear plants produce radioactive waste. To pay for the cost of
storing, transporting and disposing these wastes in a permanent
location, in the United States a surcharge of a tenth of a cent per kilowatt-hour is added to electricity bills.
Roughly one percent of electrical utility bills in provinces using
nuclear power are diverted to fund nuclear waste disposal in Canada.
In 2009, the Obama administration announced that the Yucca Mountain nuclear waste repository
would no longer be considered the answer for U.S. civilian nuclear
waste. Currently, there is no plan for disposing of the waste and
plants will be required to keep the waste on the plant premises
indefinitely.
The disposal of low level waste reportedly costs around £2,000/m³ in the UK. High level waste costs somewhere between £67,000/m³ and £201,000/m³. General division is 80%/20% of low level/high level waste, and one reactor produces roughly 12 m³ of high level waste annually.
In Canada, the NWMO
was created in 2002 to oversee long term disposal of nuclear waste, and
in 2007 adopted the Adapted Phased Management procedure. Long term
management is subject to change based on technology and public opinion,
but currently largely follows the recommendations for a centralized
repository as first extensively outlined by AECL in 1988. It was
determined after extensive review that following these recommendations
would safely isolate the waste from the biosphere. The location has not
yet been determined, and the project is expected to cost between $9 and
$13 billion CAD for construction and operation for 60–90 years,
employing roughly a thousand people for the duration. Funding is
available and has been collected since 1978 under the Canadian Nuclear
Fuel Waste Management Program. Very long term monitoring requires less
staff since high-level waste is less toxic than naturally occurring
uranium ore deposits within a few centuries.
The primary argument for pursuing IFR-style technology today is
that it provides the best solution to the existing nuclear waste problem
because fast reactors can be fueled from the waste products of existing
reactors as well as from the plutonium used in weapons, as is the case
of the discontinued EBR-II in Arco, Idaho, and in the operating, as of 2014, BN-800 reactor. Depleted uranium
(DU) waste can also be used as fuel in fast reactors. Waste produced
by a fast-neutron reactor and a pyroelectric refiner would consist only
of fission products, which are produced at a rate of about one tonne per
GWe-year. This is 5% as much as present reactors produce, and needs
special custody for only 300 years instead of 300,000. Only 9.2% of
fission products (strontium and caesium)
contribute 99% of radiotoxicity; at some additional cost, these could
be separated, reducing the disposal problem by a further factor of ten.
Decommissioning
At the end of a nuclear plant's lifetime, the plant must be
decommissioned. This entails either dismantling, safe storage or
entombment. In the United States, the Nuclear Regulatory Commission
(NRC) requires plants to finish the process within 60 years of closing.
Since it may cost $500 million or more to shut down and decommission a
plant, the NRC requires plant owners to set aside money when the plant
is still operating to pay for the future shutdown costs.
Decommissioning a reactor that has undergone a meltdown is
inevitably more difficult and expensive. Three Mile Island was
decommissioned 14 years after its incident for $837 million. The cost of the Fukushima disaster cleanup is not yet known, but has been estimated to cost around $100 billion. Chernobyl is not yet decommissioned, different estimates put the end date between 2013 and 2020.
Proliferation and terrorism
A 2011 report for the Union of Concerned Scientists stated that "the costs of preventing nuclear proliferation and terrorism
should be recognized as negative externalities of civilian nuclear
power, thoroughly evaluated, and integrated into economic
assessments—just as global warming emissions are increasingly identified
as a cost in the economics of coal-fired electricity".
"Construction of the ELWR was completed in 2013 and is optimized
for civilian electricity production, but it has "dual-use" potential and
can be modified to produce material for nuclear weapons."
Nuclear safety and security
is a chief goal of the nuclear industry. Great care is taken so that
accidents are avoided, and if unpreventable, have limited consequences.
Accidents could stem from system failures related to faulty construction
or pressure vessel embrittlement due to prolonged radiation exposure.
As with any aging technology, risks of failure increase over time, and
since many currently operating nuclear reactors were built in the mid
20th century, care must be taken to ensure proper operation. Many more
recent reactor designs have been proposed, most of which include passive safety
systems. These design considerations serve to significantly mitigate or
totally prevent major accidents from occurring, even in the event of a
system failure. Still, reactors must be designed, built, and operated
properly to minimize accident risks. The Fukushima disaster represents one instance where these systems were not comprehensive enough, where the tsunami following the Tōhoku earthquake disabled the backup generators that were stabilizing the reactor. According to UBS AG, the Fukushima I nuclear accidents have cast doubt on whether even an advanced economy like Japan can master nuclear safety. Catastrophic scenarios involving terrorist attacks are also conceivable.
An interdisciplinary team from MIT estimated that given the expected growth of nuclear power from 2005 to 2055, at least four core damage incidents would be expected in that period (assuming only current designs were used – the number of incidents expected in that same time period with the use of advanced designs is only one). To date, there have been five core damage incidents in the world since 1970 (one at Three Mile Island in 1979; one at Chernobyl in 1986; and three at Fukushima-Daiichi in 2011), corresponding to the beginning of the operation of generation II reactors.
According to the Paul Scherrer Institute, the Chernobyl incident is the only incident ever to have caused any fatalities. The report that UNSCEAR
presented to the UN General Assembly in 2011 states that 29 plant
workers and emergency responders died from effects of radiation
exposure, two died from causes related to the incident but unrelated to
radiation, and one died from coronary thrombosis. It attributed fifteen
cases of fatal thyroid cancer to the incident. It said there is no
evidence the incident caused an ongoing increase in incidence of solid
tumors or blood cancers in Eastern Europe.
In terms of nuclear accidents, the Union of Concerned Scientists
have claimed that "reactor owners ... have never been economically
responsible for the full costs and risks of their operations. Instead,
the public faces the prospect of severe losses in the event of any
number of potential adverse scenarios, while private investors reap the
rewards if nuclear plants are economically successful. For all practical
purposes, nuclear power's economic gains are privatized, while its
risks are socialized".
However, the problem of insurance costs for worst-case scenarios is not unique to nuclear power: hydroelectric power plants are similarly not fully insured against a catastrophic event such as the Banqiao Dam disaster, where 11 million people lost their homes and from 30,000 to 200,000 people died, or large dam failures in general.
Private insurers base dam insurance premiums on worst-case scenarios,
so insurance for major disasters in this sector is likewise provided by
the state.
In the US, insurance coverage for nuclear reactors is provided by the
combination of operator-purchased private insurance and the primarily
operator-funded Price Anderson Act.
Any effort to construct a new nuclear facility around the world,
whether an existing design or an experimental future design, must deal
with NIMBY or NIABY objections. Because of the high profiles of the Three Mile Island accident and Chernobyl disaster, relatively few municipalities welcome a new nuclear reactor, processing plant, transportation route, or deep geological repository within their borders, and some have issued local ordinances prohibiting the locating of such facilities there.
Nancy Folbre,
an economics professor at the University of Massachusetts, has
questioned the economic viability of nuclear power following the 2011 Japanese nuclear accidents:
The proven dangers of nuclear power amplify the economic risks of
expanding reliance on it. Indeed, the stronger regulation and improved
safety features for nuclear reactors called for in the wake of the
Japanese disaster will almost certainly require costly provisions that
may price it out of the market.
The cascade of problems at Fukushima, from one reactor to another,
and from reactors to fuel storage pools, will affect the design, layout
and ultimately the cost of future nuclear plants.
In 1986, Pete Planchon conducted a demonstration of the inherent safety of the Integral Fast Reactor.
Safety interlocks were turned off. Coolant circulation was turned
off. Core temperature rose from the usual 1000 degrees Fahrenheit to
1430 degrees within 20 seconds. The boiling temperature of the sodium
coolant is 1621 degrees. Within seven minutes the reactor had shut
itself down without action from the operators, without valves, pumps,
computers, auxiliary power, or any moving parts. The temperature was
below the operating temperature. The reactor was not damaged. The
operators were not injured. There was no release of radioactive
material. The reactor was restarted with coolant circulation but the
steam generator disconnected. The same scenario recurred. Three weeks
later, the operators at Chernobyl repeated the latter experiment,
ironically in a rush to complete a safety test, using a very different
reactor, with tragic consequences. Safety of the Integral Fast Reactor
depends on the composition and geometry of the core, not efforts by
operators or computer algorithms.
Insurance
Insurance available to the operators of nuclear power plants varies by nation. The worst case nuclear accident costs
are so large that it would be difficult for the private insurance
industry to carry the size of the risk, and the premium cost of full
insurance would make nuclear energy uneconomic.
However, the problem of insurance costs for worst-case scenarios is not unique to nuclear power: hydroelectric power plants are similarly not fully insured against a catastrophic event such as the Banqiao Dam disaster, where 11 million people lost their homes and from 30,000 to 200,000 people died, or large dam failures in general.
Private insurers base dam insurance premiums on worst-case scenarios,
so insurance for major disasters in this sector is likewise provided by
the state.
In Canada, the Canadian Nuclear Liability Act requires nuclear
power plant operators to obtain $650 million (CAD) of liability
insurance coverage per installation (regardless of the number of
individual reactors present) starting in 2017 (up from the prior $75
million requirement established in 1976), increasing to $750 million in
2018, to $850 million in 2019, and finally to $1 billion in 2020.
Claims beyond the insured amount would be assessed by a government
appointed but independent tribunal, and paid by the federal government.
In the UK, the Nuclear Installations Act 1965
governs liability for nuclear damage for which a UK nuclear licensee is
responsible. The limit for the operator is £140 million.
In the United States, the Price-Anderson Act
has governed the insurance of the nuclear power industry since 1957.
Owners of nuclear power plants are required to pay a premium each year
for the maximum obtainable amount of private insurance ($450 million)
for each licensed reactor unit.
This primary or "first tier" insurance is supplemented by a second
tier. In the event a nuclear accident incurs damages in excess of $450
million, each licensee would be assessed a prorated share of the excess
up to $121,255,000. With 104 reactors currently licensed to operate,
this secondary tier of funds contains about $12.61 billion. This results
in a maximum combined primary+secondary coverage amount of up to $13.06
billion for a hypothetical single-reactor incident. If 15 percent of
these funds are expended, prioritization of the remaining amount would
be left to a federal district court. If the second tier is depleted,
Congress is committed to determine whether additional disaster relief is
required. In July 2005, Congress extended the Price-Anderson Act to newer facilities.
The cost per unit of electricity produced (kWh) will vary according
to country, depending on costs in the area, the regulatory regime and
consequent financial and other risks, and the availability and cost of
finance. Costs will also depend on geographic factors such as
availability of cooling water, earthquake likelihood, and availability
of suitable power grid connections. So it is not possible to accurately
estimate costs on a global basis.
Commodity prices rose in 2008, and so all types of plants became more expensive than previously calculated.
In June 2008 Moody's estimated that the cost of installing new nuclear
capacity in the United States might possibly exceed $7,000/KWe in final cost.
In comparison, the reactor units already under construction in China
have been reported with substantially lower costs due to significantly
lower labour rates.
In 2009, MIT updated its 2003 study, concluding that inflation
and rising construction costs had increased the overnight cost of
nuclear power plants to about $4,000/kWe, and thus increased the power cost to $0.084/kWh. The 2003 study had estimated the cost as $0.067/kWh.
A 2013 study indicates that the cost competitiveness of nuclear
power is "questionable" and that public support will be required if new
power stations are to be built within liberalized electricity markets.
In 2014, the US Energy Information Administration
estimated the levelized cost of electricity from new nuclear power
plants going online in 2019 to be $0.096/kWh before government
subsidies, comparable to the cost of electricity from a new coal-fired
power plant without carbon capture, but higher than the cost from
natural gas-fired plants.
In 2019 the US EIA revised the levelized cost of electricity from
new advanced nuclear power plants going online in 2023 to be
$0.0775/kWh before government subsidies, using a regulated industry 4.3%
cost of capital (WACC - pre-tax 6.6%) over a 30-year cost recovery period. Financial firm Lazard
also updated its levelized cost of electricity report costing new
nuclear at between $0.118/kWh and $0.192/kWh using a commercial 7.7%
cost of capital (WACC - pre-tax 12% cost for the higher-risk 40% equity finance and 8% cost for the 60% loan finance) over a 40 year lifetime.
Comparisons with other power sources
Generally, a nuclear power plant is significantly more expensive to
build than an equivalent coal-fueled or gas-fueled plant. If natural gas
is plentiful and cheap operating costs of conventional power plants is
less. Most forms of electricity generation produce some form of negative externality — costs imposed on third parties that are not directly paid by the producer — such as pollution
which negatively affects the health of those near and downwind of the
power plant, and generation costs often do not reflect these external
costs.
A comparison of the "real" cost of various energy sources is complicated by a number of uncertainties:
The cost of environmental damage caused by any energy source through
land use (whether for mining fuels or for power generation), air and
water pollution, solid waste production, manufacturing-related damages
(such as from mining and processing ores or rare earth elements), etc.
The cost and political feasibility of disposal of the waste from reprocessedspent nuclear fuel
is still not fully resolved. In the United States, the ultimate
disposal costs of spent nuclear fuel are assumed by the U.S. government
after producers pay a fixed surcharge.
Operating reserve
requirements are different for different generation methods. When
nuclear units shut down unexpectedly they tend to do so independently,
so the "hot spinning reserve" must be at least the size of the largest
unit. On the other hand, some renewable energy sources (such as
solar/wind power) are intermittent power sources with uncontrollably varying outputs, so the grid will require a combination of demand response, extra long-range transmission infrastructure, and large-scale energy storage. (Some firm renewables such as hydroelectricity have a storage reservoir and can be used as reliable back-up power for other power sources.)
Potential governmental instabilities in the plant's lifetime. Modern nuclear reactors
are designed for a minimum operational lifetime of 60 years (extendible
to 100+ years), compared to the 40 years (extendible to 60+ years) that
older reactors were designed for.
Actual plant lifetime (to date, no nuclear plant has been shut down
solely due to reaching its licensed lifetime. Over 87 reactors in the
United States have been granted extended operating licenses to 60 years
of operation by the NRC as of December 2016, and subsequent license renewals could extend that to 80 years.
Modern nuclear reactors are also designed to last longer than older
reactors as outlined above, allowing for even further increased plant
lifetimes.)
Due to the dominant role of initial construction costs and the
multi-year construction time, the interest rate for the capital required
(as well as the timeline that the plant is completed in) has a major
impact on the total cost of building a new nuclear plant.
Lazard's report on the estimated levelized cost of energy by source
(10th edition) estimated unsubsidized prices of $97–$136/MWh for
nuclear, $50–$60/MWh for solar PV, $32–$62/MWh for onshore wind, and
$82–$155/MWh for offshore wind.
However, the most important subsidies to the nuclear industry do
not involve cash payments. Rather, they shift construction costs and
operating risks from investors to taxpayers and ratepayers, burdening
them with an array of risks including cost overruns, defaults to
accidents, and nuclear waste management. This approach has remained
remarkably consistent throughout the nuclear industry's history, and
distorts market choices that would otherwise favor less risky energy
investments.
In 2011, Benjamin K. Sovacool
said that: "When the full nuclear fuel cycle is considered — not only
reactors but also uranium mines and mills, enrichment facilities, spent
fuel repositories, and decommissioning sites — nuclear power proves to
be one of the costliest sources of energy".
In 2014, Brookings Institution published The Net Benefits of Low and No-Carbon Electricity Technologies
which states, after performing an energy and emissions cost analysis,
that "The net benefits of new nuclear, hydro, and natural gas combined
cycle plants far outweigh the net benefits of new wind or solar plants",
with the most cost effective low carbon power technology being determined to be nuclear power. Moreover, Paul Joskow of MIT maintains that the "Levelized cost of electricity"
(LCOE) metric is a poor means of comparing electricity sources as it
hides the extra costs, such as the need to frequently operate back up
power stations, incurred due to the use of intermittent power sources such as wind energy, while the value of baseload power sources are underpresented.
A 2017 focused response to these claims, particularly "baseload" or "back up", by Amory Lovins in 2017, countered with statistics from operating grids.
Other economic issues
Kristin Shrader-Frechette
analysed 30 papers on the economics of nuclear power for possible
conflicts of interest. She found of the 30, 18 had been funded either by
the nuclear industry or pro-nuclear governments and were pro-nuclear,
11 were funded by universities or non-profit non-government organisations
and were anti-nuclear, the remaining 1 had unknown sponsors and took
the pro-nuclear stance. The pro-nuclear studies were accused of using
cost-trimming methods such as ignoring government subsidies and using
industry projections above empirical evidence where ever possible. The
situation was compared to medical research where 98% of industry
sponsored studies return positive results.
Nuclear power plants tend to be competitive in areas where other fuel resources are not readily available — France, most notably, has almost no native supplies of fossil fuels. France's nuclear power experience has also been one of paradoxically increasing rather than decreasing costs over time.
Making a massive investment of capital in a project with long-term recovery might affect a company's credit rating.
A Council on Foreign Relations
report on nuclear energy argues that a rapid expansion of nuclear power
may create shortages in building materials such as reactor-quality
concrete and steel, skilled workers and engineers, and safety controls
by skilled inspectors. This would drive up current prices.
It may be easier to rapidly expand, for example, the number of coal
power plants, without this having a large effect on current prices.
Existing nuclear plants generally have a somewhat limited ability
to significantly vary their output in order to match changing demand (a
practice called load following). However, many BWRs, some PWRs (mainly in France), and certain CANDU reactors (primarily those at Bruce Nuclear Generating Station)
have various levels of load-following capabilities (sometimes
substantial), which allow them to fill more than just baseline
generation needs. Several newer reactor designs also offer some form of
enhanced load-following capability. For example, the Areva EPR can slew its electrical output power between 990 and 1,650 MW at 82.5 MW per minute.
The number of companies that manufacture certain parts for
nuclear reactors is limited, particularly the large forgings used for
reactor vessels and steam systems. In 2010, only four companies (Japan Steel Works, China First Heavy Industries, Russia's OMZ Izhora and Korea's Doosan Heavy Industries) manufacture pressure vessels for reactors of 1100 MWe or larger. Some have suggested that this poses a bottleneck that could hamper expansion of nuclear power internationally, however, some Western reactor designs require no steel pressure vessel such as CANDU
derived reactors which rely on individual pressurized fuel channels.
The large forgings for steam generators — although still very heavy —
can be produced by a far larger number of suppliers.
For a country with both a nuclear power industry and a nuclear arms industry, synergies between the two can favor a nuclear power plant with an otherwise uncertain economy. For example, in the United Kingdom researchers have informed MPs that the government was using the Hinkley Point C project
to cross-subsidise the UK military's nuclear-related activity by
maintaining nuclear skills. In support of that, researchers from the University of SussexAndy Stirling and Phil Johnstone stated that the costs of the Trident nuclear submarine programme would be prohibitive without “an effective subsidy from electricity consumers to military nuclear infrastructure”.
The nuclear power industry in Western nations has a history of construction delays, cost overruns, plant cancellations, and nuclear safety issues despite significant government subsidies and support. In December 2013, Forbes magazine reported that, in developed countries, "reactors are not a viable source of new power".
Even in developed nations where they make economic sense, they are not
feasible because nuclear's “enormous costs, political and popular opposition, and regulatory uncertainty”. This view echoes the statement of former Exelon CEO John Rowe,
who said in 2012 that new nuclear plants “don’t make any sense right
now” and won't be economically viable in the foreseeable future. John Quiggin,
economics professor, also says the main problem with the nuclear option
is that it is not economically-viable. Quiggin says that we need more efficient energy use and more renewable energy commercialization. Former NRC member Peter A. Bradford and Professor Ian Lowe have recently made similar statements.
However, some "nuclear cheerleaders" and lobbyists in the West continue
to champion reactors, often with proposed new but largely untested
designs, as a source of new power.
Significant new build activity is occurring in developing
countries like South Korea, India and China. China has 25 reactors under
construction,
However, according to a government research unit, China must not build
"too many nuclear power reactors too quickly", in order to avoid a
shortfall of fuel, equipment and qualified plant workers.
The 1.6 GWe EPR reactor is being built in Olkiluoto Nuclear Power Plant, Finland. A joint effort of French AREVA and German Siemens AG, it will be the largest pressurized water reactor
(PWR) in the world. The Olkiluoto project has been claimed to have
benefited from various forms of government support and subsidies,
including liability limitations, preferential financing rates, and
export credit agency subsidies, but the European Commission's investigation didn't find anything illegal in the proceedings.
However, as of August 2009, the project is "more than three years
behind schedule and at least 55% over budget, reaching a total cost
estimate of €5 billion ($7 billion) or close to €3,100 ($4,400) per
kilowatt".
Finnish electricity consumers interest group ElFi OY evaluated in 2007
the effect of Olkiluoto-3 to be slightly over 6%, or €3/MWh, to the
average market price of electricity within Nord Pool Spot. The delay is therefore costing the Nordic countries
over 1.3 billion euros per year as the reactor would replace more
expensive methods of production and lower the price of electricity.
Russia has launched the world's first floating nuclear power plant. The £100 million vessel, the Akademik Lomonosov, is the first of seven plants (70 MWe per ship) that Moscow says will bring vital energy resources to remote Russian regions. Startup of the first of the ships two reactors was announced in December 2018.
Following the Fukushima nuclear disaster
in 2011, costs are likely to go up for currently operating and new
nuclear power plants, due to increased requirements for on-site spent
fuel management and elevated design basis threats. After Fukushima, the International Energy Agency halved its estimate of additional nuclear generating capacity built by 2035.
Many license applications filed with the U.S. Nuclear Regulatory Commission for proposed new reactors have been suspended or cancelled. As of October 2011, plans for about 30 new reactors in the United States have been reduced to 14.
There are currently five new nuclear plants under construction in the
United States (Watts Bar 2, Summer 2, Summer 3, Vogtle 3, Vogtle 4). Matthew Wald from The New York Times has reported that "the nuclear renaissance is looking small and slow".
In 2013, four aging, uncompetitive reactors were permanently
closed in the US: San Onofre 2 and 3 in California, Crystal River 3 in
Florida, and Kewaunee in Wisconsin. The Vermont Yankee
plant closed in 2014. New York State is seeking to close Indian Point
Nuclear Power Plant, in Buchanan, 30 miles from New York City.
The additional cancellation of five large reactor uprates (Prairie
Island, 1 reactor, LaSalle, 2 reactors, and Limerick, 2 reactors), four
by the largest nuclear company in the United States, suggest that the
nuclear industry faces "a broad range of operational and economic
problems".
As of July 2013, economist Mark Cooper
has identified some US nuclear power plants that face particularly
significant challenges to their continued operation due to regulatory
policies.
These are Palisades, Fort Calhoun (meanwhile closed for economical
reasons), Nine Mile Point, Fitzpatrick, Ginna, Oyster Creek (same as Ft.
Calhoun), Vermont Yankee (same as Ft. Calhoun), Millstone, Clinton,
Indian Point. Cooper said the lesson here for policy makers and
economists is clear: "nuclear reactors are simply not competitive". An 2017 analysis by Bloomberg showed that over half of U.S. nuclear plants were running at a loss, first of all those at a single unit site.
