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COMPLAINTS HANDLING PROCEDURE

Kenya Nuclear Electricity Board is dedicated to ensuring utmost professionalism when it comes to service delivery.

What is a complaint

A complaint is an expression of dissatisfaction made against the Board or about the service delivery of the members of staff of the Board or about any policy of the Board.

 KNEB will invesitgate any complaints in confidence and act on them accordingly.

The standard procedure for handling complaints is as follows:

  1. The Complaints Handling Officer designated by the committee shall receive complaints on a monthly basis
  2. The designated Complaints Handling Officer shall pass the information in writing on the number and natures of complaints in writing to the chairperson of the committee within the first three working days of the month
  3. The chairperson shall make arrangements for the Complaints Handling & Management committee to meet within three working days from the date s/he was informed of the complaints.
  4. The Complaints Handling Officer shall investigate all the complaints and decide on their eligibility
  5. If the complaints are not eligible, the committee shall dismiss them through the Complaints Handling Officer who will transmit the information to the complainant in writing within seven days. The process shall end there. If the complaints are eligible, the process shall continue from iv.
  6. The committee shall after the investigations, discuss and recommend the corrective actions to the appropriate Head Of Department in writing, for implementations of the actions within a stipulated period of time.
  7. The Head Of Department shall report in writing on the corrective actions undertaken
  8. The Complaints Handling Officer shall investigate the corrective actions taken. If satisfied with the actions, the Complaints Handling & Management committee shall communicate in writing to the user, through the CHO.
  9. If the Complaints Handling Officer is not satisfied with the corrective actions taken, the Complaints Handling & Management committee shall communicate back in writing to the Head Of Department for necessary actions to be implemented. If the Head Of Department refuses to cooperate the Complaints Handling & Management committee shall communicate in writing to the Commission on Administration of Justice for further action

 Click to download the standard procedure for handling complaints for more details

 

 

 

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Welcome to KNEB E-learning on Nuclear Power

KNEB Nuclear E-learning is an open elearning platform that is designed to provide stakeholders with knowledge and understanding on various aspects of Nuclear power. The stakeholders include

Decision makers, advisers and senior managers in governmental organizations, regulatory bodies, utilities and industries, as well as donors, suppliers and other related bodies;

Students, academics and researchers in the nuclear field and;

Those involved in expanding existing nuclear power programmes.

Click to visit KNEB Nuclear Elearning

  • The USA is the world's largest producer of nuclear power, accounting for more than 30% of worldwide nuclear generation of electricity.
  • The country's 100 nuclear reactors produced 798 billion kWh in 2015, over 19% of total electrical output. There are four reactors under construction.
  • Following a 30-year period in which few new reactors were built, it is expected that four more new units will come online by 2021, these resulting from 16 licence applications made since mid-2007 to build 24 new nuclear reactors.
  • Government policy changes since the late 1990s have helped pave the way for significant growth in nuclear capacity. 
  • Some states have liberalized wholesale electricity markets, which makes the financing of capital-intensive power projects difficult, and coupled with lower gas prices since 2009, have put the economic viability of some existing reactors and proposed projects in doubt.
  • Jordan imports most of its energy and seeks greater energy security as well as lower electricity prices.
  • It is aiming to have two 1000 MWe nuclear power units in operation by 2025 to provide nearly half the country’s electricity.
  • Jordan has significant uranium resources, some in phosphorite deposits.

Jordan imports over 95% of its energy needs, at a cost of about one-fifth of its GDP. It generated 17.3 TWh, mostly from oil, and imported 0.3 TWh net in 2013 for its six million people, consumption being 14.5 TWh. In 2012, due to gas supply constraints from Egypt, its electricity supply supply was 84% from heavy fuel oil and diesel, instead of natural gas which previously provided the majority, and 5% was imported. In 2013, 74% of electricity was from oil.

It has 2400 MWe of generating capacity and expected to need 3600 MWe by 2015, 5000 MWe by 2020 and 8000 MWe by 2030 when it expects doubled electricity consumption. About 6800 MWe of new plant is needed by 2030, with one third of this projected to be nuclear. Per capita electricity consumption is about 2000 kWh/yr. Jordan has regional grid connection of 500 MWe with Egypt, 300 MWe with Syria, and it is increasing links with Israel and Palestine. This will both increase energy security and provide justification for larger nuclear units.

Also it has a "water deficit" of about 600 million cubic metres per year (1500 demand, 900 supply). It pumps about 60 million m3/yr of fossil subartesian water from the Disi/Saq aquifer, and this is set to rise to 160 million m3/yr in 2013. It contains elevated, but not hazardous, levels of radionuclides, principally radium. (Drinking 2 litres per day would give a dose of 1.0 to 1.5 mSv/yr.)

Jordan's 2007 national energy strategy envisaged 29% of primary energy from natural gas, 14% from oil shale, 10% from renewables and 6% from nuclear by 2020.

  • Nuclear power capacity worldwide is increasing steadily, with over 60 reactors under construction in 15 countries.
  • Most reactors on order or planned are in the Asian region, though there are major plans for new units in Russia.
  • Significant further capacity is being created by plant upgrading.
  • Plant life extension programs are maintaining capacity, in USA particularly.

Today there are some 440 nuclear power reactors operating in 31 countries plus Taiwan, with a combined capacity of over 385 GWe. In 2014 these provided 2411 billion kWh, over 11% of the world's electricity.

Over 60 power reactors are currently being constructed in 13 countries plus Taiwan (see Table below), notably China, South Korea, UAE and Russia.

Each year, the OECD's International Energy Agency (IEA) sets out the present situation and also reference and other, particularly carbon reduction scenarios. World Energy Outlook 2014 had a special focus on nuclear power, and extends the scope of scenarios to 2040. In its New Policies scenario, installed nuclear capacity growth is 60% through 543 GWe in 2030 and to 624 GWe in 2040 out of a total of 10,700 GWe, with the increase concentrated heavily in China (46% of it), plus India, Korea and Russia (30% of it together) and the USA (16%), countered by a 10% drop in the EU. Despite this, the percentage share of nuclear power in the global power mix increases to only 12%, well below its historic peak. Low-Nuclear and so-called High-Nuclear cases give 366 and 767 GWe nuclear respectively in 2040. The low-carbon ‘450 Scenario’ gives a cost-effective transition to limiting global warming assuming an effective international agreement in 2015, and this brings about more than doubling nuclear capacity to 862 GWe in 2040, while energy-related CO2 emissions peak before 2020 and then decline. In this scenario, almost all new generating capacity built after 2030 needs to be low-carbon.

"Despite the challenges it currently faces, nuclear power has specific characteristics that underpin the commitment of some countries to maintain it as a future option," it said. "Nuclear plants can contribute to the reliability of the power system where they increase the diversity of power generation technologies in the system. For countries that import energy, it can reduce their dependence on foreign supplies and limit their exposure to fuel price movements in international markets."

It is noteworthy that in the 1980s, 218 power reactors started up, an average of one every 17 days. These included 47 in USA, 42 in France and 18 in Japan. These were fairly large - average power was 923.5 MWe. So it is not hard to imagine a similar number being commissioned in the years ahead. But with China and India getting up to speed in nuclear energy and a world energy demand increasing, a realistic estimate of what is possible (but not planned at this stage) might be the equivalent of one 1000 MWe unit worldwide every 5 days.

Increased capacity

Increased nuclear capacity in some countries is resulting from the uprating of existing plants. This is a highly cost-effective way of bringing on new capacity.

There is a question of scale, and large units will not fit into small grids. A conservative guide is that peak power demand must be met with effective installed capacity and about 20% reserve margin. Also, the largest single plant should not be more than 10% of base-load, or 5% of peak demand.

Numerous power reactors in USA, Belgium, Sweden and Germany, for example, have had their generating capacity increased.

In Switzerland, the capacity of its five reactors has been increased by 13.4%.

In the USA, the Nuclear Regulatory Commission has approved more than 140 uprates totalling over 6500 MWe since 1977, a few of them "extended uprates" of up to 20%.

Spain has had a program to add 810 MWe (11%) to its nuclear capacity through upgrading its nine reactors by up to 13%. Most of the increase is already in place. For instance, the Almarez nuclear plant was boosted by 7.4% at a cost of US$ 50 million.

Finland Finland boosted the capacity of the original Olkiluoto plant by 29% to 1700 MWe. This plant started with two 660 MWe Swedish BWRs commissioned in 1978 and 1980. The Loviisa plant, with two VVER-440 (PWR) reactors, has been uprated by 90 MWe (10%).

Sweden's utilities have uprated all three plants. The Ringhals plant was uprated by about 305 MWe over 2006-14. Oskarshamn 3 was uprated by 21% to 1450 MWe at a cost of €313 million. Forsmark 2 had a 120 MWe uprate (12%) to 2013.

Nuclear plant construction

Most reactors currently planned are in the Asian region, with fast-growing economies and rapidly-rising electricity demand.

Many countries with existing nuclear power programs (Argentina, Armenia, Brazil, Bulgaria, China, Czech Rep., India, Pakistan, Romania, Russia, Slovakia, South Korea, South Africa, UAE, Ukraine, UK, USA) have plans to build new power reactors (beyond those now under construction).

In all, over 160 power reactors with a total net capacity of some 182,000 MWe are planned and over 300 more are proposed. Energy security concerns and greenhouse constraints on coal burning have combined with basic economics to put nuclear power back on the agenda for projected new capacity in many countries.

In the USA there are plans for five new reactors, beyond the five under construction now. It is expected that some of the new reactors will be on line by 2020.

In Finland, construction is now under way on a fifth, very large reactor which is expected to come on line in 2018, and plans are progressing for another large one to follow it.

France is building a similar 1600 MWe unit at Flamanville, for operation from 2018.

In the UK, four similar 1600 MWe units are planned, and a further 6000 MWe is proposed.

Romania's second power reactor istarted up in 2007, and plans are being implemented for two further Canadian units to be built there.

Slovakia is completing two 470 MWe units at Mochovce, to operate from 2017.

Bulgaria is planning to build a large new reactor at Kozloduy.

Belarus is building two large new Russian reactors at Ostrovets.

In Russia, several reactors and two small ones are under active construction, and one recently put into operation is a large fast neutron reactor. About 25 further reactors are then planned, some to replace existing plants. This will increase the country's present nuclear power capacity significantly by 2030. In addition about 5 GW of nuclear thermal capacity is planned. A small floating power plant is expected to be commissioned by 2018 and others are planned to follow.

Poland is planning two 3000 MWe nuclear power plants.

South Korea plans to bring a further further four reactors into operation by 2018, and another eight by about 2030, giving total new capacity of 17,200 MWe. All of these are the Advanced PWRs of 1400 MWe. These APR-1400 designs have evolved from a US design which has US NRC design certification, and four been sold to the UAE (see below).

Japan has two reactors under construction but another three which were likely to start building by mid-2011 have been deferred.

In China, now with 32 operating reactors on the mainland, the country is well into the growth phase of its nuclear power programme. There were eight new grid connections in 2015. Over 20 more reactors are under construction, including the world's first Westinghouse AP1000 units, and a demonstration high-temperature gas-cooled reactor plant. Many more units are planned, including two largely indigenous designs – the Hualong One and CAP1400. China aims to more than double its nuclear capacity by 2020.

India has 21 reactors in operation, and six under construction. This includes two large Russian reactors and a large prototype fast breeder reactor as part of its strategy to develop a fuel cycle which can utilise thorium. Over 20 further units are planned. 18 further units are planned, and proposals for more - including western and Russian designs - are taking shape following the lifting of trade restrictions.

Pakistan has third and fourth 300 MWe reactors under construction at Chashma, financed by China. Two larger Chinese power reactors are planned.

In Kazakhstan, a joint venture with Russia's Atomstroyexport envisages development and marketing of innovative small and medium-sized reactors, starting with a 300 MWe Russian design as baseline for Kazakh units.

In Iran a 1000 MWe PWR at Bushehr came on line in 2011, and further units are planned.

The United Arab Emirates awarded a $20.4 billion contract to a South Korean consortium to build four 1400 MWe reactors by 2020. They are under construction, on schedule.

Jordan has committed plans for its first reactor, and is developing its legal and regulatory infrastructure.

Turkey has contracts signed for four 1200 MWe Russian nuclear reactors at one site and four European ones at another. Its legal and regulatory infrastructure is well-developed.

Vietnam has committed plans for its first reactors at two sites (2x2000 MWe), and is developing its legal and regulatory infrastructure. The first plant will be a turnkey project built by Atomstroyexport. The second will be Japanese.

Fuller details of all the above are in linked country papers.

Plant life extension and retirements

Most nuclear power plants originally had a nominal design lifetime of 25 to 40 years, but engineering assessments of many plants have established that many can operate longer. In the USA over 75 reactors have been granted licence renewals which extend their operating lives from the original 40 out to 60 years, and operators of most others are expected to apply for similar extensions. Such licence extensions at about the 30-year mark justify significant capital expenditure for replacement of worn equipment and outdated control systems.

In France, there are rolling ten-year reviews of reactors. In 2009 the Nuclear Safety Authority (ASN) approved EdF's safety case for 40-year operation of the 900 MWe units, based on generic assessment of the 34 reactors. There are plans to take reactor lifetimes out to 60 years, involving substantial expenditure.

The Russian government is extending the operating lives of most of the country's reactors from their original 30 years, for 15 years, or for 25 years in the case of the newer VVER-1000 units, with significant upgrades.

The technical and economic feasibility of replacing major reactor components, such as steam generators in PWRs, and pressure tubes in CANDU heavy water reactors, has been demonstrated. The possibilities of component replacement and licence renewals extending the lifetimes of existing plants are very attractive to utilities, especially in view of the public acceptance difficulties involved in constructing replacement nuclear capacity.

On the other hand, economic, regulatory and political considerations have led to the premature closure of some power reactors, particularly in the United States, where reactor numbers have fell from 110 to 99, in eastern Europe, in Germany and likely in Japan.

It should not be assumed that reactors will close when their licence is due to expire, since licence renewal is now common. However, new plants coming on line are balanced by old plants being retired. Over 1996-2015, 75 reactors were retired as 80 started operation. There are no firm projections for retirements over the next two decades, but the World Nuclear Association estimates that at least 60 of those now operating will close by 2030, most being small plants. The 2015 WNA Nuclear Fuel Report reference case has 132 reactors closing by 2035, using very conservative assumptions about licence renewal, and 287 coming on line, including many in China.

The World Nuclear Power Reactor table gives a fuller and (for current year) possibly more up to date overview of world reactor status.

Power reactors under construction

Start †   Reactor Type Gross MWe
2016 India, NPCIL Kudankulam 2 PWR 950
2016 India, NPCIL Kakrapar 3 PHWR 640
2016 India, Bhavini Kalpakkam FBR 470
2016 Russia, Rosenergoatom Novovoronezh II-1 PWR 1070
2016 USA, TVA Watts Bar 2 PWR 1180
2016 China, CNNC Sanmen 1 PWR 1250
2016 China, SPI Haiyang 1 PWR 1250
2016 China, CNNC Changjiang 2 PWR 650
2016 China, CNNC Fuqing 3 PWR 1080
2016 China, CGN Fangchenggang 2 PWR 1080
2016 India, NPCIL Rajasthan 7 PHWR 640
2016 Pakistan, PAEC Chashma 3 PWR 300
         
2017 Slovakia, SE Mochovce 3 PWR 440
2017 Russia, Rosenergoatom Pevek FNPP PWR x 2 70
2017 Russia, Rosenergoatom Leningrad II-1 PWR 1070
2017 UAE, ENEC Barakah 1 PWR 1400
2017 China, CGN Taishan 1 PWR 1700
2017 China, CGN Taishan 2 PWR 1700
2017 China, CNNC Sanmen 2 PWR 1250
2017 China, SPI Haiyang 2 PWR 1250
2017 China, CGN Yangjiang 4 PWR 1080
2017 China, CNNC Fuqing 4 PWR 1080
2017 China, China Huaneng Shidaowan HTR 200
2017 China, CNNC Tianwan 3 PWR 1060
2017 Russia, Rosenergoatom Rostov 4 PWR 1200
2017 Korea, KHNP Shin-Kori 4 PWR 1350
2017 Korea, KHNP Shin-Hanul 1 PWR 1350
2017 India, NPCIL Kakrapar 4 PHWR 640
2017 India, NPCIL Rajasthan 8 PHWR 640
2017 Pakistan, PAEC Chashma 4 PWR 300
         
2018 Russia, Rosenergoatom Novovoronezh II-2 PWR 1070
2018 Slovakia, SE Mochovce 4 PWR 440
2018 France, EdF Flamanville 3 PWR 1600
2018 Finland, TVO Olkilouto 3 PWR 1720
2018 Korea, KHNP Shin-Hanul 2 PWR 1350
2018 UAE, ENEC Barakah 2 PWR 1400
2018 Brazil Angra 3 PWR 1405
2018 Argentina Carem25 PWR 27
2018 China, CGN Yangjiang 5 PWR 1080
2018 China, CNNC Tianwan 4 PWR 1060
         
2019 USA, Southern Vogtle 3 PWR 1200
2019 USA, SCEG Summer 2 PWR 1200
2019 UAE, ENEC Barakah 3 PWR 1400
2019 China, CGN Fangchenggang 3 PWR 1150
2019 China, CGN Hongyanhe 5 PWR 1120
2019 China, CGN Yangjiang 6 PWR 1080
2019 China, CNNC Fuqing 5 PWR 1150
2019 Romania, SNN Cernavoda 3 PHWR 720
         
2020 Russia, Rosenergoatom Leningrad II-2 PWR 1070
2020 China, CGN Hongyanhe 6 PWR 1120
2020 China, CGN Ningde 5 PWR 1150
2020 China, CGN Fangchenggang 4 PWR 1150
2020 China, CNNC Fuqing 6 PWR 1150
2020 UAE, ENEC Barakah 4 PWR 1400
2020 Romania, SNN Cernavoda 4 PHWR 720

† Latest announced year of proposed commercial operation

Sources:
World Nuclear Association information papers

 

  • The first commercial nuclear power stations started operation in the 1950s.
  • There are over 440 commercial nuclear power reactors operable in 31 countries, with over 390,000 MWe of total capacity. About 60 more reactors are under construction.
  • They provide over 11% of the world's electricity as continuous, reliable base-load power, without carbon dioxide emissions.
  • 55 countries operate a total of about 245 research reactors, and a further 180 nuclear reactors power some 140 ships and submarines.

Nuclear technology uses the energy released by splitting the atoms of certain elements. It was first developed in the 1940s, and during the Second World War to 1945 research initially focussed on producing bombs which released great energy by splitting the atoms of particular isotopes of either uranium or plutonium.

In the 1950s attention turned to the peaceful purposes of nuclear fission, notably for power generation. Today, the world produces as much electricity from nuclear energy as it did from all sources combined in the early years of nuclear power. Civil nuclear power can now boast over 16,800 reactor years of experience and supplies almost 11.5% of global electricity needs, from reactors in 31 countries. In fact, through regional transmission grids, many more than those countries depend on nuclear-generated power.

Many countries have also built research reactors to provide a source of neutron beams for scientific research and the production of medical and industrial isotopes.

Today, only eight countries are known to have a nuclear weapons capability. By contrast, 55 countries operate about 245 civil research reactors, over one-third of these in developing countries. Now 31 countries host some 447 commercial nuclear power reactors with a total installed capacity of over 390,000 MWe (see linked table for up to date figures). This is more than three times the total generating capacity of France or Germany from all sources. About 60 further nuclear power reactors are under construction, equivalent to 16% of existing capacity, while over 160 are firmly planned, equivalent to nearly half of present capacity.
 

Nuclear Electricity Production column graph

Sixteen countries depend on nuclear power for at least a quarter of their electricity. France gets around three-quarters of its power from nuclear energy, while Belgium, Czech Republic, Finland, Hungary, Slovakia, Sweden, Switzerland, Slovenia and Ukraine get one-third or more. South Korea and Bulgaria normally get more than 30% of their power from nuclear energy, while in the USA, UK, Spain, Romania and Russia almost one-fifth is from nuclear. Japan is used to relying on nuclear power for more than one-quarter of its electricity and is expected to return to that level. Among countries which do not host nuclear power plants, Italy and Denmark get almost 10% of their power from nuclear.

In electricity demand, the need for low-cost continuous, reliable supply can be distinguished from peak demand occurring over few hours daily and able to command higher prices. Supply needs to match demand instantly and reliably over time. There are number of characteristics of nuclear power which make it particularly valuable apart from its actual generation cost per unit – MWh or kWh. Fuel is a low proportion of power cost, giving power price stability, and is stored onsite (not depending on continuous delivery). The power from nuclear plants is dispatchable on demand, it can be fairly quickly ramped-up, it contributes to clean air and low-CO2 objectives, it gives good voltage support for grid stability. Reactors can be made to load-follow. These attributes are mostly not monetised in merchant markets, but have great value which is increasingly recognised where dependence on intermittent sources has grown.

There is a clear need for new generating capacity around the world, both to replace old units which contribute a lot of CO2 emissions, and to meet increased expectations for electricity in many countries. There are about 127,000 generating units worldwide, 96.5% of these of 300 MWe or less, and one-quarter of the fossil fuel plants are over 30 years old. There is scope for both large new plants and small ones to replace existing units 1:1, all with near-zero CO2 emissions.

World Nuclear Association projections made in 2016 suggest a 26.7% increase to 494 GWe in operation in 2030 and overall 40% increase to 546 GWe in 2035. (Low and high projections are 368 and 631 GWe for 2030, and 365 and 719 GWe for 2035.)

Improved performance from existing nuclear reactors

As nuclear power plant construction returns to the levels reached during the 1970s and 1980s, those plants now operating are producing more electricity. In 2011, production was 2518 billion kWh. The increase over the six years to 2006 (210 TWh) was equal to the output from 30 large new nuclear power plants. Yet between 2000 and 2006 there was no net increase in reactor numbers (and only 15 GWe in capacity). The rest of the improvement was due to better performance from existing units.

In a longer perspective, from 1990 to 2010, world capacity rose by 57 GWe (17.75%, due both to net addition of new plants and uprating some established ones) and electricity production rose 755 billion kWh (40%). The relative contributions to this increase were: new construction 36%, uprating 7% and availability increase 57%. In 2011 and 2012 both capacity and output diminished due to cutbacks in Germany and Japan following the Fukushima accident.

Considering 400 power reactors over 150 MWe for which data are available: over 1980 to 2000 world median capacity factor increased from 68% to 86%, and since then it has maintained around 85%. Actual load factors are slightly lower: 80% average in 2012 (excluding Japan), due to reactors being operated below their full capacity for various reasons. One-quarter of the world's reactors have load factors of more than 90%, and nearly two-thirds do better than 75%, compared with only about a quarter of them over 75% in 1990. The USA now dominates the top 25 positions, followed by South Korea, but six other countries are also represented there. Four of the top ten reactors for lifetime load factors are South Korean.

US nuclear power plant performance has shown a steady improvement over the past 20 years, and the average load factor in 2012 was 81%, up from 66% in 1990 and 56% in 1980. US average capacity factors have been over 90% in most years since 2000

 

 

- 92.7% in 2015. This places the USA as the performance leader with nearly half of the top 50 reactors, the 50th achieving 94% in 2015-16 (albeit without China and South Korea in those figures). The USA accounts for nearly one-third of the world's nuclear electricity.

In 2015-16, twelve countries with four or more units averaged better than 80% load factor, to which China and South Korea should probably be added, and  French reactors averaged 83%, despite many being run in load-following mode, rather than purely for base-load power.

Some of these figures suggest near-maximum utilisation, given that most reactors have to shut down every 18-24 months for fuel change and routine maintenance. In the USA this used to take over 100 days on average but in the last decade it has averaged about 40 days. Another performance measure is unplanned capability loss, which in the USA has for the last few years been below 2%.
 

World Electricity Production 2012 pie graph

World overview

All parts of the world are involved in nuclear power development, and a few examples follow.

China

The Chinese government plans to increase nuclear generating capacity to 58 GWe with 30 GWe more under construction by 2021. China has completed construction and commenced operation of over 30 new nuclear power reactors since 2002, and some 20 new reactors are under construction. These include the world's first four Westinghouse AP1000 units and a demonstration high-temperature gas-cooled reactor plant. Many more are planned, with construction due to start within about three years. China is commencing export marketing of a largely indigenous reactor design. R&D on nuclear reactor technology in China is second to none.

India

India’s target is to have 14.5 GWe nuclear capacity on line by 2020 as part of its national energy policy. These reactors include light- and heavy water reactors as well as fast reactors. In addition to the 22 online, of both indigenous and foreign design, five power reactors are under construction, including a 500 MWe prototype fast breeder reactor. This will take India's ambitious thorium programme to stage 2, and set the scene for eventual utilization of the country's abundant thorium to fuel reactors.

Russia

Russia plans to increase its nuclear capacity to 30.5 GWe by 2020, using its world-class light water reactors. A large fast breeder unit, the country's second, is producing power and development proceeds on others. An initial floating power plant is under construction, with delivery due in 2018. Russia leads the world in nuclear reactor exports, building and financing new nuclear power plants in several countries.

Europe

Finland and France are both expanding their fleets of nuclear power plants with the 1650 MWe EPR from Areva, two of which are also being built in China. Several countries in Eastern Europe are currently constructing or have firm plans to build new nuclear power plants (Bulgaria, Czech Republic, Hungary, Romania, Slovakia, Slovenia and Turkey).

A UK government energy paper in mid-2006 endorsed the replacement of the country’s ageing fleet of nuclear reactors with new nuclear build, and four 1600 MWe French units are planned for operation by 2023. The government aims to have 16 GWe of new nuclear capacity operating by 2030.

Sweden is closing down some older reactors, and has invested heavily in life extensions and uprates. Hungary, Slovakia and Spain are all implementing or planning for life extensions on existing plants. Germany agreed to extend the operating lives of its nuclear plants, reversing an earlier intention to shut them down, but has again reversed policy following the Fukushima accident and is phasing out nuclear generation by about 2023.

Poland is developing a nuclear program, with 6000 MWe planned. Estonia and Latvia are involved in a joint project with established nuclear power producer Lithuania. Belarus has started construction of its first two Russian reactors.

United States

In the USA, there are four reactors under construction, all new AP1000 designs. One of the reasons for the hiatus in new build in the USA to date has been the extremely successful evolution in maintenance strategies. Over the last 15 years, changes have increased utilization of US nuclear power plants, with the increased output corresponding to 19 new 1000 MW plants being built.

South America

Argentina and Brazil both have commercial nuclear reactors generating electricity, and additional reactors are under construction. Chile has a research reactor in operation and has the infrastructure and intention to build commercial reactors.

South Korea

South Korea has three new reactors under construction domestically as well as four in the UAE. It plans for eight more. It is also involved in intense research on future reactor designs.

SE Asia

Vietnam intends to have it first nuclear power plant operating about 2028 with Russian help and a second soon after with Japanese input. Indonesia and Thailand are planning nuclear power programs.

South Asia

Bangladesh has contracted with Russia to build its first nuclear power plant. Pakistan with Chinese help is building three small reactors inland and two large ones near Karachi.

Central Asia

Kazakhstan with its abundance of uranium is working closely with Russia in planning development of small new reactors for its own use and export.

Middle East

The United Arab Emirates is building four 1450 MWe South Korean reactors at a cost of over $20 billion and is collaborating closely with IAEA and experienced international firms. Iran’s first power reactor is in operation, and more are planned.

Saudi Arabia, Jordan and Egypt are also moving towards employing nuclear energy for power and desalination.

Africa

South Africa is committed to plans for 9600 MWe of further nuclear power capacity.

Nigeria has sought the support of the International Atomic Energy Agency to develop plans for two 1000 MWe reactors.

New countries

In September 2012 the International Atomic Energy Agency (IAEA) expected seven newcomer countries to launch nuclear programs in the near term. It did not name these, but Lithuania, UAE, Turkey, Belarus, Vietnam, Poland, and Bangladesh appear likely candidates. Others had stepped back from commitment, needed more time to set up infrastructure, or did not have credible finance.

See also WNA paper Emerging Nuclear Energy Countries.

Other nuclear reactors

In addition to commercial nuclear power plants, there are about 245 research reactors operating, in 55 countries, with more under construction. These have many uses including research and the production of medical and industrial isotopes, as well as for training.

The use of reactors for marine propulsion is mostly confined to the major navies where it has played an important role for five decades, providing power for submarines and large surface vessels. At least 140 ships, mostly submarines, are propelled by some 180 nuclear reactors and over 13,000 reactor-years of experience has been gained with marine reactors. Russia and the USA have decommissioned many of their nuclear submarines from the Cold War era.

Russia also operates a fleet of six large nuclear-powered icebreakers and a 62,000 tonne cargo ship. It is also completing a floating nuclear power plant with two 40 MWe reactors for use in remote regions.
 

Nuclear Generation by Country 2013 bar graph

 

Note: Taipower used nuclear energy to generate 16% of electricity on the island of Taiwan in 2014.

  • Energy resources are available to supply the world's expanding needs without environmental detriment.
  • Wastes remain a major consideration whether they are released to the environment or not.
  • Ethical principles seem increasingly likely to influence energy policy in many countries, which augurs well for nuclear energy.
  • The competitive position of nuclear energy "is robust from a sustainable development perspective since most health and environmental costs are already internalised."1

Until about 30 years ago, energy sustainability was thought of simply in terms of availability relative to the rate of use. Today, in the context of the ethical framework of sustainable development, including particularly concerns about global warming, other aspects are also very important. These include environmental effects and the question of wastes, even if they have no environmental effect. Safety is also an issue, as well as the broad and indefinite aspect of maximising the options available to future generations. Geopolitical questions of energy security are central to the assessment of sustainability for individual countries, along with the affordability of the electricity produced.

Sustainable development criteria have been pushed into the front line of energy policy. In the light of concerns about climate change due to apparent human enhancement of the greenhouse effect, there is growing concern about how we address energy needs on a sustainable basis.

Energy demand

A number of factors are widely agreed. The world's population will continue to grow for several decades at least. Energy demand is likely to increase even faster, and the proportion supplied by electricity will also grow faster still. However, opinions diverge as to whether the electricity demand will continue to be served predominantly by extensive grid systems, or whether there will be a strong trend to distributed generation (close to the points of use). That is an important policy question itself, but either way, it will not obviate the need for more large-scale grid-supplied power, especially in urbanised areas, over the next several decades. Much demand is for continuous, reliable supply of electricity on a large scale, and this qualitative consideration will continue to dominate.

The key question is how we generate that electricity. Today, worldwide, 68% comes from fossil fuels (41% coal, 21% gas, 5.5% oil), 13.4% from nuclear fission and 19% from hydro and other renewable sources. There is no prospect that we can do without any of these (though oil has a more vital role in other applications).

Sources of energy

Harnessing renewable energy such as wind and solar is an appropriate first consideration in sustainable development, because apart from constructing the plant, there is no depletion of mineral resources and no direct air or water pollution. In contrast to the situation even a few decades ago, we now have the technology to access wind on a significant scale for electricity, and with some subsidy on a minority of supply being from those sources, they are affordable. But harnessing these 'free' sources cannot be the only option. Renewable sources other than hydro – notably wind and solar – are diffuse, intermittent, and unreliable by nature of their occurrence. These aspects offer a technological challenge of some magnitude, given that electricity cannot be stored on any large scale. For instance, solar-sourced electricity requires collecting energy at a peak density of about 1 kilowatt (kW) per square metre when the sun is shining to satisfy a quite different kind of electricity demand – one which mostly requires a relatively continuous supply.

Wind is the fastest-growing source of electricity in many countries, and there is a lot of scope for further expansion. While the rapid expansion of wind turbines in many countries has been welcome, capacity is seldom more than 30% utilised over the course of a week or year, which testifies to the unreliability of the source and the fact that it does not and cannot match the pattern of demand. Wind is intermittent, and when it does not blow, back-up capacity such as hydro or gas is needed. When it does blow, and displaces power from other sources, it reduces the economic viability of those sources and hence increases prices.

The rapid expansion of wind farms and solar power capacity is helped considerably by generous government-mandated grants, subsidies and other arrangements ultimately paid for by consumers. Where the financial inducements to build wind and solar capacity result in a strong response however, the subsidies become unaffordable and are now being cut back in many countries. Also there is often a strong groundswell of opposition on aesthetic grounds from the countryside where wind turbines are located.

Renewable sources such as wind and solar are intrinsically unsuited to meeting the demand for continuous, reliable supply on a large scale – which comprises most demand in developed countries.

A fuller treatment of electricity from renewable sources is in the information page on Renewable Energy and Electricity.

Apart from renewables, it is a question of what is most abundant and least polluting. Today, to a degree almost unimaginable even 30 years ago, there is known to be an abundance of many energy resources in the ground. Coal and uranium (not to mention thorium) are available and unlikely to be depleted this century.

The criteria for any acceptable energy supply will continue to be cost, safety, and security of supply, as well as environmental considerations. Addressing environmental effects usually has cost implications, as the current climate change debate makes clear. Supplying low-cost electricity with acceptable safety and low environmental impact will depend substantially on developing and deploying reasonably sophisticated technology. This includes both large-scale and small-scale nuclear energy plants, which can be harnessed directly to industrial processes such as hydrogen production or desalination, as well as their traditional role in generating electricity.

IAEA classification of nuclear energy scenario sustainability

  • Level 1. Safe, secure, economical and publicly acceptable nuclear power with security of supply – addresses conditions necessary for newcomers to deploy nuclear energy.
  • Level 2. Safe disposal of all nuclear wastes in a complete once-through fuel cycle with thermal reactors and with retrievable spent nuclear fuel disposal. Level 2 addresses political issue of 'solving the waste problem'. Retrievability is required to not limit future generations’ options.
  • Level 3. Initiate recycling of used nuclear fuel to reduce wastes. Limited recycle that reduces high-level waste volumes, slightly improves U utilisation, and keeps most of the U more accessible (Depleted U and Recovered U/Th). A branch of Level 3 is a once-through breed and burn option, providing significant improvement in resource utilization (up to 10 times).
  • Level 4. Guarantee nuclear fuel resources for at least the next 1000 years via complete recycle of used fuel. Closed fuel cycle with breeding of fissile material (from 238U or 232Th) to improve natural resource utilisation by a factor of 10 to 100. Solves the resource utilisation issue by providing fuel for thousands of years while also significantly reducing long-lived radioactivity burden (Pu-233/U recycle).
  • Level 5. Reduce radiotoxicity of all wastes below natural uranium level. Closed fuel cycle recycling all actinides and only disposing fission products to minimise long-term radiotoxicity of nuclear waste. Achieves additional substantial reduction of long-lived radioactivity burden (Pu-233/U/minor actinide recycle) and reduces radiotoxicity of waste down to natural uranium levels within 1000 years. As an option, transmutation of long-lived fission produces could be considered to further reduce waste radiotoxicity.

Is nuclear energy renewable?

Generally 'renewable' relates to harnessing energy from natural forces which are renewed by natural processes, especially wind, waves, sun and rain, but also heat from the Earth's crust and mantle. Although it shares many attributes with technologies harnessing these natural forces – for instance radioactive decay produces much of the heat harnessed geothermally – nuclear power is usually categorised separately from ‘renewables’.

Conventional nuclear power reactors do use a mineral fuel and demonstrably deplete the available resources of that fuel. In such a reactor, the input fuel is uranium-235 (U-235), which is part of a much larger mass of uranium – mostly U-238. This U-235 is progressively 'burned' to yield heat. But about one-third of the energy yield comes from something which is not initially loaded in: plutonium-239 (Pu-239), which behaves almost identically to U-235. Some of the U-238 turns into Pu-239 through the capture of neutron particles, which are released when the U-235 is 'burned'. So the U-235 used actually renews itself to some extent by producing Pu-239 from the otherwise waste material U-238.

This process can be optimised in fast neutron reactors, which are likely to be extensively deployed in the next generation of nuclear power reactors. A fast neutron reactor can be configured to 'breed' more Pu-239 than it consumes (by way of U-235 + Pu-239), so that the system can run indefinitely. While it can produce more fuel than it uses, there does need to be a steady input of reprocessing activity to separate the fissile plutonium from the uranium and other materials discharged from the reactors. This is fairly capital-intensive but well-proven and straightforward. The used fuel from the whole process is recycled and the usable part of it increases incrementally.

As well as utilizing about 60 times the amount of energy from uranium, fast neutron reactors will unlock the potential of using even more abundant thorium as a fuel (see information page on Thorium).  Using a fast neutron reactor, thorium produces U-233, which is fissile. This process is not yet commercialised, but it works and if there were ever a pressing need for it, development would be accelerated. India is the only country concentrating on this now, since in a world context uranium is so abundant and relatively cheap.  In addition, some 1.5 million tonnes of depleted uranium now seen by some people as little more than a waste, becomes a fuel resource. The consequence of this is that the available resource of fuel for fast neutron reactors is so plentiful that under no practical terms would the fuel source be significantly depleted.

Regardless of the various definitions of 'renewable', nuclear power therefore meets every reasonable criterion for sustainability, which is the prime concern.

Energy resources

There is abundant coal in many parts of the world, but with the constraints imposed by concern about global warming, it is likely that this will increasingly be seen as chemical feedstock and its large-scale use for electricity production will be scaled down. Current proposals for 'clean coal' technologies may change this outlook. The main technology involves the capture and subsequent storage of the carbon dioxide from the flue gas. Elements of the technology are proven but the challenge is to actually commercialize it and bring the cost down sufficiently to compete with nuclear power.

Natural gas is also reasonably abundant, especially with the advent of technologies for tapping that in coal seams and shales, but is so valuable for direct use after being reticulated to the point where heat is required, and as a chemical feedstock, that its large-scale use for power generation makes little sense and is arguably unsustainable. However, while abundant supply keeps prices down in the short to medium-term, it is the most economical means of generating electricity in some places, notably North America.

Fuel for nuclear power is abundant, and uranium is even available from sea water at costs which would have little impact on electricity prices. Furthermore, if well-proven but currently uneconomic fast neutron reactor technology is used, or thorium becomes a nuclear fuel, the supply is almost limitless. (See information page on Supply of Uranium.)

The hydrogen economy

Someday, hydrogen is expected to come into great demand as a transport fuel which does not contribute to global warming. It may be used in fuel cells to produce electricity or directly in internal combustion motors – as experimentally now.

Fuel cells are at an early stage of technological development and still require substantial, research and development input, although they are likely to be an important technology in the future.

Hydrogen may be provided by steam reforming of natural gas (in which case the emission of by-product CO2 has to be taken into account), by electrolysis of water, or (in future) by thermochemical processes using nuclear heat. Today, about 96% of hydrogen is made from fossil fuels: half from natural gas, 30% from liquid hydrocarbons and 18% from coal. This gives rise to quantities of carbon dioxide emissions - each tonne produced gives rise to 11 tonnes of CO2.

 Some new types of nuclear reactor such as high-temperature gas cooled reactors (HTRs), operating at around 950°C have the potential for producing hydrogen from water by thermochemical means, without using natural gas, and without any CO2 arising.

Large-scale use of electrolysis would mean a considerable increase in electricity demand. However, this need not be continuous baseload supply, as hydrogen can be accumulated and stored, and solar or wind generation may well serve this purpose better than supplying consumer electricity demand.

However, pending the development of affordable mass-produced fuel cells, a significant increase in base-load electricity demand may result from the adoption of plug-in electric hybrid vehicles and full electric vehicles (see information page on Electricity and Cars). These are on the threshold of commercial availability (today's hybrid vehicles only need bigger battery capacity and the facility to use mains power for recharging).

Wastes

Wastes – both those produced and those avoided – are a major concern in any consideration of sustainable development.

Burning fossil fuels produces primarily carbon dioxide as waste, which is inevitably dumped into the atmosphere. With black coal, approximately one tonne of carbon dioxide results from every thousand kilowatt hours generated. Natural gas contributes about half as much CO2 as coal from actual combustion, and also some (including methane leakage) from its extraction and distribution. Oil and gas burned in transporting fossil fuels adds to the global total. As yet, there is no satisfactory way to avoid or dispose of the greenhouse gases which result from fossil fuel combustion.

Nuclear wastes

Nuclear energy produces both operational and decommissioning wastes, which are contained and managed. Although experience with both storage and transport over half a century clearly shows that there is no technical problem in managing any civil nuclear wastes without environmental impact, the question has become political, focussing on final disposal. In fact, nuclear power is the only energy-producing industry which takes full responsibility for all its wastes, and costs this into the product – a key factor in sustainability.

Ethical, environmental and health issues related to nuclear wastes are topical, and their prominence has tended to obscure the fact that such wastes are a declining hazard, while other industrial wastes retain their toxicity indefinitely.

Regardless of whether particular wastes remain a problem for centuries or millennia or forever, there is a clear need to address the question of their safe disposal. If they cannot readily be destroyed or denatured, this generally means that they need to be removed and isolated from the biosphere. This may be permanent, or retrievable.

An alternative view asserts that indefinite surface storage of high-level wastes under supervision is preferable. This may be because such materials have some potential for recycling as a fuel source, or negatively because progress towards successful geological disposal would simply encourage continued use and expansion of nuclear energy. However, there is wide consensus that dealing effectively with wastes to achieve high levels of safety and security is desirable in a 50-year perspective, ensuring that each generation deals with its own wastes.

According to the OECD's Nuclear Energy Agency: "The scientific and technical community generally feels confident that there already exist technical solutions to the spent fuel and nuclear waste conditioning and disposal question. This is a consequence of the many years of work by numerous professionals in institutions around the world... There is a wide consensus on the safety and benefits of geologic disposal."2

Ethical aspects of nuclear wastes

In a 1999 OECD article3, Claudio Pescatore outlines some ethical dimensions of this question. He starts on a very broad canvas, quoting four fundamental principles proposed by the US National Academy of Public Administration4:

  • Trustee Principle: Every generation has obligations as trustee to protect the interests of future generations.
  • Sustainability Principle: No generation should deprive future generations of the opportunity for a quality of life comparable to its own.
  • Chain of Obligation Principle: Each generation's primary obligation is to provide for the needs of the living and succeeding generations. Near-term concrete hazards have priority over long-term hypothetical hazards.
  • Precautionary Principle: Actions that pose a realistic threat of irreversible harm or catastrophic consequences should not be pursued unless there is some compelling, countervailing need to benefit either current or future generations.

These four principles resulted from a request by the US Government to elucidate principles for guiding decisions by public administrators on the basis of the international Rio and UNESCO Declarations5 which acknowledge responsibilities to future generations. The principles can be applied to the question of nuclear wastes, and in particular to their deep geological disposal, a system with inherent passive safety. Referring to relevant 1995 IAEA and NEA publicationsa, Dr Pescatore summarises the principles in this context as follows:

  • The generation producing the waste is responsible for its safe management and associated costs.
  • There is an obligation to protect individuals and the environment both now and in the future.
  • There is no moral basis for discounting future health and risks of environmental damage.
  • Our descendants should not knowingly be exposed to risks which we would not accept today. Individuals should be protected at least as well as they are at present.
  • The safety and security of repositories should not presume a stable social structure for the indefinite future or continued technological progress.
  • Wastes should be processed so they will not to be a burden to future generations. However, we should not unnecessarily limit the capability of future generations to assume management control, including possible recovery of the wastes.
  • We are responsible for passing on to future generations our knowledge concerning the risks related to waste.
  • There should be enough flexibility in the disposal procedures to allow alternative choices. In particular information should be made available so the public can take part in the decision-making process which, in this case, will proceed in stages.

Deep geological disposal is considered as the final stage in waste management. It should ensure security and safety in a way that will not require surveillance, maintenance, or institutional control.

External costs

Some energy sources dispose of wastes to the environment or have health effects which are not costed into the product. These implicit subsidies, or external costs as they are generally called, are nevertheless real and usually quantifiable, but are borne by society at large. Their quantification is necessary to enable rational choices of energy sources. Nuclear energy has always provided for waste disposal and decommissioning costs in the actual cost of electricity (ie it has internalised them), so that external costs are minimal.

The External costs of Energy (ExternE) European Research Network has compared the external costs of various means of generating electricityb. It showed that coal has the highest external costs (and about the same for all other generation costs), followed by gas, while nuclear and wind were one tenth or less of coal. The methodology included the risk of accidents and covered full fuel cycle. Hence if external costs are taken into account, nuclear energy is shown as very competitive.

Safety

The safety of nuclear energy has been well demonstrated, notwithstanding the continued operation of a small number of reactors which are, by western standards, distinctly unsatisfactory. These include two old Soviet designs, one of which – before some very extensive modifications to the type – precipitated the 1986 Chernobyl disaster. Over 14,500 reactor-years of operation have shown a remarkable lack of problems in any of the reactors which are licensable in most of the world.  The only serious accident to a Western plant in over 30 years was that precipitated by an unprecedented tsunami at Fukushima in March 2011. Even then, and despite massive inconvenience to many people due to evacuation, the lack of human casualties from the accident contrasted with some 25,000 killed by the actual tsunami.

There is probably no other large-scale technology used worldwide with a comparable safety record. This is largely because safety was given a very high priority from the outset of the civil nuclear energy program, at least in the West. The safety provisions include a series of physical barriers between the hot radioactive reactor core and the environment, and the provision of multiple safety systems, each with back-up, and designed to accommodate human error. Safety systems, in the sense of back-ups and containment, account for a substantial part of the capital cost of nuclear power reactors - a higher proportion even than in aircraft design and construction.

Any statistics comparing the safety of nuclear energy with alternative means of generating electricity show nuclear to be the safest. In fact, Chernobyl and Fukushima are the only blemishes on the record, and Chernobyl is of very little relevance to the safety of most of the world's reactors.

Energy security

From a national perspective, the security of future energy supplies is a major factor in assessing their sustainability. Whenever objective assessment is made of national or regional energy policies, security of supply is a priority.

France's decision in 1974 to expand dramatically its use of nuclear energy was driven primarily by considerations of energy security. However, the economic virtues have since become more prominent. Various EU reports over the last decade have highlighted the importance of nuclear power for Europe's energy security and climate goals.  Many governments are clear that nuclear energy must play an increasing role by 2030, and in recent years the formerly rather negative UK government has been foremost in declaring this.

Opportunity costs

Nuclear energy and renewables have one important feature in common. They give us access to virtually limitless resources of energy with negligible opportunity cost – we are not depleting resources useful for other purposes, and we are using relatively abundant rather than less abundant energy. We can envisage a time when fossil carbon-based fuels will be too valuable to burn on the present scale.

Outlook

Recent analyses fail to come up with any 50-year scenario based on sustainable development principles which does not depend significantly on nuclear fission to provide large-scale, highly intensive energy, along with renewables to meet some small-scale (and especially dispersed) low-intensity needs. The alternative is either to squander fossil carbon resources or deny the aspirations of hundreds of millions of people in the next generation.

Alternative low-CO2 means of producing base-load electricity have not been credibly proposed, and wildly unrealistic projections for renewables of a few years ago have tended to become muted. Certainly all the reputable energy scenarios show the main load being carried by coal, gas, and nuclear, with the share between them depending on economic factors in the context of various levels of CO2 emission constraints.

 As the notion of sustainability is increasingly supported politically, all external costs are likely to be factored in, thus affecting the economic choices among fuels for electricity generation in nuclear power's favour.

 

There is now sufficient solar and wind capacity operating on grid systems for their advantages and limitations to be widely evident. That will help focus public discussion on the real options for continuous, reliable (baseload) electricity generation on the large scale required. Nuclear power can – and must – contribute significantly to sustainable development.

  • The human enhancement of global warming leading to climate change is seen as a worldwide problem.
  • Policy responses have been led by international negotiation, but have been qualified or indecisive at the national level, and so far largely ineffective, despite strong international agreement on the matter. 
  • The principal focus is on reducing carbon dioxide emissions.
  • Nuclear power is seldom acknowledged as the single most significant means of limiting the increase in greenhouse gas concentrations while enabling access to abundant electricity.

Emissions of greenhouse gases have a global impact, unlike some other forms of pollution. Whether they are emitted in Asia, Africa, Europe, or the Americas, they rapidly disperse evenly across the globe. This is one reason why efforts to address climate change have been through international collaboration and agreement.

The principal forum for international climate change action has been the United Nations, which has led to the Framework Convention on Climate Change (UNFCCC) and the Kyoto Protocol. However, more recently other international approaches have been put in place, the Asia Pacific Partnership and agreements under the G8, starting with their 2005 meeting in Gleneagles, UK. In December 2015 the Paris agreement consolidated years of negotiations with agreement among 188 countries to limit carbon dioxide emissions.

Although climate change agreements emphasising carbon emission reduction have been reached through international approaches, the policy measures to meet the obligations and objectives set by such agreements have been implemented at the national or regional level. Here they are supplemented by policy instruments such as efficiency standards and incentives to invest in infrastructure which does not give rise to carbon emissions. Pricing carbon emissions is seen as putting a price on a major external cost from energy production and transformation.

The UN climate change negotiations, early phase

In 1988 the World Meteorological Organization (WMO) and the United Nations Environment Programme (UNEP) set up the Intergovernmental Panel on Climate Change (IPCC), an expert body that would assess scientific information on climate change. As a reaction to the concerns raised in the IPCC's First Assessment Report the UN General Assembly established the Intergovernmental Negotiating Committee for a Framework Convention on Climate Change. The UN Framework Convention on Climate Change (UNFCCC) was adopted in May 1992 and entered into force in 1994. The convention included the commitment to stabilise greenhouse gas emissions at 1990 levels by 2000.

The first Convention of the Parties to the UNFCCC (COP 1) was held in 1995. Negotiations at this and two subsequent COPs led to agreement on the Kyoto Protocol in 1997. The Kyoto Protocol set out specific commitments by individual developed countries to reduced emissions by an average of 5.2% below 1990 levels by the period 2008-2012. However, it would take three further meetings until the "Marrakesh Accords" were agreed, which provide sufficient detail on the procedures for pursuing objectives set out in the Kyoto Protocol.

The Kyoto Protocol involved several decisions:

  • By 2012, developed countries would reduce their collective emissions by 5.2% from 1990 levels, each country being committed to a particular figure.
  • The emissions covered by the Protocol are not only carbon dioxide, but also methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride.
  • These commitments would be reckoned on a net basis, considering sinks as well as sources, and each country must credibly measure its contribution and meet its commitment.
  • Countries may fulfil their commitments jointly (such as with regional agreements) and they may improve the efficiency of compliance through "flexibility mechanisms".

In order for the Kyoto Protocol to enter into force and become legally binding it had to be ratified by at least 55 countries and for those ratifying countries to include enough Annex I (developed) countries to represent at least 55% of the total emissions from those Annex 1 countries in 1990. In 2001 the US Government (which had earlier signed the Protocol) announced that it would not ratify the Protocol. As the USA emits more than a quarter of all greenhouse gas emissions from developed countries, this put the ratification of the Protocol in jeopardy. Australia also declared that it would not ratify, though it would pursue emission reductions as agreed.

Eventually, entry into force depended on the decision of Russia, another large greenhouse gas emitter. After some delay Russia notified the United Nations of its decision to ratify the Protocol in November 2004 and 90 days later, on February 19, 2005, the Protocol finally came into force. Australia subsequently ratified the Protocol in December 2007.

While countries that are party to the Protocol are expected to rely mainly on reducing their own emissions domestically, three "flexibility mechanisms" were identified to improve the economic efficiency of reductions and make it easier for parties to comply. The three mechanisms are emissions trading, Joint Implementation and the Clean Development Mechanism.

Emissions Trading: A market-based approach to achieving environmental objectives that allows those countries or entities reducing greenhouse gas emissions below what is required to use or trade the excess reductions to offset emissions at another source, inside or outside the country. In general, trading can occur at the domestic, regional (EU), international and intra-company levels. A precedent is the USA acid rain program, which successfully trades permits for sulfur dioxide.

Joint Implementation (JI): A project-based mechanism, whereby one developed country – with emissions caps – can work with another to reduce emissions or enhance sinks, and share the resulting emission reduction units accordingly.

The Clean Development Mechanism (CDM): A project-based mechanism where certified projects proposed by developed countries – or companies from those countries – can be used to reduce emissions in developing countries. The developed country – or company – earns certified emission reduction units, which may be used against the country's own reduction commitment. CDM is primarily focused on development aid and secondly on emission reduction.

The Kyoto Protocol and nuclear energy

The role of nuclear energy in combating climate change received a lot of attention during the UNFCCC negotiations between COP 4 and COP 7 (1998-2002). This was due to the entrenched anti-nuclear position of some of the environment NGOs lobbying at the negotiations and the tendency for national delegations to be dominated by those from Environment Departments, with a historically more negative position towards nuclear energy than their overall national position.

Nuclear energy is discriminated against within the Marakesh Accords, specifically within the sections dealing with the Clean Development Mechanism and Joint Implementation, but currently the effect of this discrimination is largely symbolic.

The Marakesh Accords state:
"Recognizing that Parties included in Annex I are to refrain from using credits (from CDM or JI projects) generated from nuclear facilities to meet their commitments under Article 3, paragraph 1" This text is convoluted, reflecting perhaps a compromise reached during the negotiations. It should be noted that CDM and JI projects involving nuclear facilities are not banned. Parties are free to put forward such projects, as they would do any other candidate project.

However, the text says that developed counties (Annex I) Parties should refrain from using any credits earned from those projects for meeting their commitments – which are the emissions targets agreed under the Kyoto Protocol. The meaning of "should refrain" is a matter of debate. Annex I Parties are also meant not to exceed their emissions targets. Should they refrain from using nuclear project credits unless it means they would miss their target?

Ultimately, this is a symbolic discussion, as the current low price of CDM and JI credits and the short time period over which credits would be awarded mean that the availability of such credits is unlikely to be a significant factor in the decision on whether to invest in nuclear energy.

Concerns over the efficacy of CDM and JI in general have been expressed, many potential investors in projects being frustrated by the bureaucratic process involved in gaining approval for a project and the relatively small rewards for doing so. Moreover, there are concerns over the limited geographical distribution of CDM projects, with the majority of projects taking place in China, India and Brazil.

However, in the longer term the CDM and JI may become a more viable mechanism for encouraging low carbon projects and development. However, it is also possible that new mechanisms will be introduced in subsequent agreements and the role of the CDM and JI may diminish.

Approaches to emissions trading and alternatives, European ETS

The question of emission permits of some kind as a basis for trading in them or trading them off has been approached in several different ways. They may be auctioned, or they can be allocated to firms on the basis of historical emissions (known as grandfathering). Within countries, emissions (eg carbon) taxes may be used rather than emissions trading, but still linked to the price of permits. An attractive feature of tradable permits is that any national scheme can be linked internationally. However, the emission caps need to be set by regulators, who have an impossible task in the light of normal uncertainties, as shown the first decade of the EU system. Also it tends to reward traders more than innovators.

The best-developed arrangement is the European Emission Trading System (ETS), which is the cornerstone of EU policy to counter climate change. The ETS is a cap-and-trade system which is seen as providing the core of a wider scheme to limit carbon emissions worldwide. By mid-2012 the ETS covered some 11,000 installations (power stations and industrial plants) in 27 EU countries plus Norway, accounting for half of the EU’s carbon emissions, or an estimated 40% in 2015. In 2011, carbon to the value of about EUR 112 billion was traded on ETS, but in 2012 this dropped to about EUR 75 billion, its lowest level since 2008.

After a positive start in 2005, in May 2006 the price of emission allowances under the ETS for the first commitment period (2005-2007) plunged to less than half their previous value, causing intense discussion on the efficacy of the whole scheme and making it clear that the caps in some states were too low to promote investment in emission reduction. Most EU countries had issued so many allowances on the basis of padded applications that they did not reach their quotas in the first year of phase one (2005-07) of the ETS, which undercut the value of traded allowances. Allowances in mid-2006 were trading at €18/tonne CO2, representing over 1.5 cents/kWh on coal-fired generation and providing a weak disincentive to using coal, especially in Germany where output constraints apply on nuclear power. For most of 2005 and until May 2006, permits were trading at over €25.

Overall in the EU, 1785 million tonnes of CO2 were emitted in 2005 against quotas of 1829 Mt, though this did not necessarily represent any decrease from what emissions would have been in the absence of the EU ETS. The UK was 33 Mt (16%) over its quota, reflecting the low target set by its government, and a swing back to coal from gas. This meant that generators (particularly) in the UK needed to purchase allowances and pass the cost on to consumers. However, it was thought that many generators had already passed on much of the price of the carbon allowances allocated to them as an "opportunity cost".

In the second commitment/ trading period of the EU ETS (Phase II, 2008-2012) emissions allowance allocations were reduced 6.5% from those in the first commitment period. However the economic crisis radically altered the situation, and from 2009 the ETS had a growing surplus of allowances and international credits because the global economic crisis had depressed emissions more than anticipated, which significantly weakened the price signal. Installations received trading credits from their national allocation plans (NAPs), administered by the governments of the 30 participating countries.

At one level it may be argued that the low price of emissions allowances in the first period could be considered as a success of the EU ETS, promoting the discovery of low-cost carbon avoidance measures. However, the credibility of the EU ETS as a part of broader climate change policies will depend on whether governments setting emissions allocations sufficiently tightly that they ensure the industries covered make a proportionate contribution towards meeting national targets, as part of the EU's overall target.

In January 2008 the European Commission (EC) proposed changes to the EU ETS in the third commitment and trading period 2013-20 which would strengthen and extend the scope of the trading scheme. NAPs would be replaced by centralised allocation by an EU authority and a single EU-wide cap on emissions which is to decrease by 1.74 % each year to 2020, when the cap would be 21% lower than the 2005 starting level. It was intended that the annual reduction would continue after 2020, with a review of the magnitude of the annual reduction to take place by 2025 at the latest. During the third commitment period a much larger share of emissions allowances would be auctioned instead of allocated free of charge. The scheme would broadened to include new industries (e.g. aluminium and ammonia producers) and new gases (nitrous oxide and perfluorocarbons). Due to the ETS having a growing surplus of allowances, the EC postponed the auctioning of some allowances as an immediate measure, and in November 2012 proposed other changes. These include increasing the EU’s 2020 emission reduction target from 20% to 30%, making the annual 1.74% reduction steeper, retiring some Phase III allowances permanently, bringing more sectors into the ETS, and limiting access to international credits. These were considered in 2013.

In January 2014 the EC published its 2030 Framework for Climate and Energy Policies, including a legislative proposal for the ETS to establish a market stability reserve (MSR) to operate in the fourth commitment and trading period (Phase IV) running 2021 to 2030. The reserve would both address the surplus of emission allowances that has built up during Phase II and which keeps the carbon price very low, and also improve the system's robustness by automatically adjusting the supply of allowances to be auctioned. Together with postponing in auctions of 900 million allowances (“backloading”), the proposal was widely supported in addressing the problems facing the rather discredited ETS. In February 2014 backloading was approved with the withdrawal of 400 million allowances that year. In May 2014 the EC said it was open to introducing the market stability measures before 2021, since the oversupply remained large.

In February 2015 the European Parliament voted in favour of a market stability reserve to operate from 2019, and for the 900 million surplus allowances to be added to it, along with 750 million unallocated allowances. In July 2015 the EC proposed putting about 250 million unallocated MSR allowances (from Phase II) plus 100 million unallocated from phase III into a phase IV new entrant reserve (NER), earmarked for new installations and significant capacity expansions. Any unused allowances due to plant closures or reduced production in phase IV will be added to the NER, making a likely total of about 395 million. It also proposed putting 50 million MSR allowances to top up an innovation fund of 400 million phase IV allowances sold by the European Investment Bank (EIB), for CCS, innovative and breakthrough technologies in energy-intensive industries. At €25/t this is worth €11.25 billion. These funding proposals are instead of keeping the MSR allowances off the market, or cancelling them.

The EC also increased the rate of reduction after 2020 to 2.2% per year, in line with the 40% domestic greenhouse gas reduction target for EU by 2030 (relative to 1990). It proposed auctioning 57% of a total 15.5 billion allowances available under the ETS cap for 2021-30, leaving 43%, about 6.3 billion, for free issue. The 57% is the same as in 2015. The original ETS Directive envisaged the free allocation of allowances to diminish to zero in 2027. Analysts expect the ETS carbon price to reach at least €20 by 2020 and €30 by 2030.

The shift from free allocation to auctioning of emissions allowances, as well as the tightening of emissions allowance caps, will benefit nuclear energy and other forms of low carbon generation. Although it is thought that the cost of emissions allowances has already been incorporated as an opportunity cost, the free allocation of allowances means that fossil fuel power plant operators have not faced a true cost themselves for much of the emissions of their plant. In particular, when new electricity generation capacity is considered, fossil fuel generation will have to incorporate the cost of carbon allowances into the economic assessment of the plant. In addition, the tightening allowance cap is likely to lead to higher allowance prices, increasing the cost of greenhouse gas emissions.

However, the ETS has arguably exported rather than reduced CO2 emissions. While the UK’s carbon emissions fell some 15% over 1990 to 2005, when imports were taken into account, carbon emissions on a world basis attributable to UK went up more than 19%, according to Professor Dieter Helm. The general trend for western countries, which substitute imports from countries like China for domestic production, is obvious. The EC is addressing this carbon leakage issue with some free allowances, and in July 2015 considered creating four “at risk” categories, from very high to low, eligible for different levels of free allowances.

Elsewhere a simple carbon emission tax has been applied (contentiously in Australia, at a level far above EU ETS but still too low and with too many exemptions to drive change, before being abandoned). This is straightforward, but the level set is arbitrary and may be out of kilter with ETS systems. Also, like the ETS, it exempts certain industries on an arbitrary or politically-driven basis, creating major inequities. And like the ETS it penalizes exporters while exempting imports.

A carbon consumption tax has been proposed, which is applied like a normal consumption tax but on the basis of CO2 implications in the production of goods and services. This would require certification of sources, not just at manufacturing level but also upstream to power generation, and at the border for imports (where assumptions re electricity inputs would need to be made). It would be equitable between domestic production and imports.Professor Dieter Helm in the UK is a proponent of this, but it is not implemented anywhere.

The ongoing UNFCCC negotiations

The protracted delays before the eventual entry into force of the Kyoto Protocol have meant that theUNFCCC negotiations began to consider what emissions reduction regime should follow the first commitment period, which ended in 2012.

Discussions followed two parallel tracks, the first considering future emissions reduction commitments for Annex I Parties to the Kyoto Protocol, the second considering long-term global cooperative action to address climate change. This second track had a more sensitive task, as it included the USA, without emissions reduction targets for the first commitment period, and also developing countries, which did not have emissions reduction targets.

Decisions on appropriate action beyond 2012 have generated a great deal of controversy. Emissions from developing countries are expected to rise as they increase their use of fossil fuels to meet their need for energy for development. Many developed countries want developing countries to limit the growth in their emissions. Developing countries point out that their per capita emission are still much lower than developed countries and believe that developed countries should show their commitment to reducing emissions first, before expecting developing countries to take action.

In 2008 and 2009 the number of meetings under the UNFCCC increased as parties worked towards a target of agreeing a legally binding agreement for after the first Kyoto Protocol commitment period. However, progress has been slower than hoped. The COP 15/CMP 5 meeting in Copenhagen in December was intended to lead to result in a high-level political agreement, with a more detailed agreement to follow, however an agreement of all Parties was not reached. The Copenhagen Accord, drawn up in the last days of the conference, included non-binding declarations of emissions reduction policies and commitments from individual governments, but no international agreement.

The COP 15/CMP 5 meeting at Copenhagen had attracted tens of thousands of delegates and had been promoted by some as the last chance to reach an agreement in time to succeed the first commitment period of the Kyoto Protocol. In addition, controversy over leaked emails from the influential University of East Anglia's Climate Research Unit had called some to question the case for action on climate change. COP 16/CMP 6 meeting in Mexico in December 2010 made little progress, but was seen as a success in that it managed to re-establish the negotiation process. However, both European and US climate change negotiators had dismissed the possibility that the COP 17/CMP 7 meeting would result in a new binding agreement. Attention turned to implementing a short-term extension of the Kyoto Protocol's first commitment period, to allow a more permanent agreement to be developed. In addition, negotiators sought to implement a number of 'fast-start' funding mechanisms that were intended to support emission reduction or avoidance projects in developing countries.

Short-term and long-term focus of UNFCCC negotiations

The ultimate objective of the Framework Convention on Climate Change is the stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system. This is a long-term objective that will require emissions paths to be reduced progressively over the 21st century and beyond.

However, the Kyoto Protocol focussed attention on a relatively short-term emissions objective, namely the first commitment period between 2008 and 2012. The targets set for this period were first agreed in 1997, which gave governments 10-15 years to put in place policies to reach these targets, and only three years between the Protocol's entry into force in 2005 and the start of the first commitment period. This bias towards short-term targets did not provide incentive to make the investments in long-term infrastructure changes, such as energy, transport and buildings, which are needed to bring sustainable reductions in greenhouse gas emissions.

Ahead of the Copenhagen COP15 meeting a number of countries declared their own national emissions reduction targets, applying to a range of timeframes. In some cases, as with the EU, parties agreed to take on more stringent emissions targets if a new agreement could eventually be reached under the UNFCCC.

A useful database of CO2 emissions per capita is EDGAR.

UN climate change conference November-December 2015, Paris

The major emphasis of the COP21 meeting in Paris was on producing a global, binding agreement to cut carbon emissions. At the Paris meeting there was clear international agreement that reducing carbon dioxide emissions was a global priority built on a groundswell of public opinion in many countries, albeit with a range of different timelines involved. It was agreed to aim for a temperature increase below 2°C and with the aim of moving to 1.5 degrees, which suggests that governments will have to introduce additional mitigation actions to move more rapidly to low-carbon technologies, especially in electricity generation. The main and widely recognised implication (which fuelled some extravagant hype stigmatising coal) is that more use must be made of low- or zero-carbon energy sources, including nuclear power.

The International Energy Agency (IEA) described it as "nothing less than a historic milestone for the global energy sector" that would "speed up the transformation of the energy sector by accelerating investments in cleaner technologies and energy efficiency." With wide support, a clean energy innovation fund is being set up to develop cleaner, more affordable and more reliable energy sources. Whatever the advances in electricity storage associated with intermittent renewables, there is now more clearly an inexorable logic for low-cost continuous reliable supply from expanded nuclear power. The IEA had already made it plain that achieving the 2°C goal would require a significant contribution from nuclear energy.

Agneta Rising, Director General of the World Nuclear Association said: "We welcome the commitments that governments have made, and the nuclear industry stands ready to help achieve the goals of the Paris agreement. This agreement should lead to a more positive outlook for nuclear investments, as nuclear is an important part of the response to climate change in countries across the world. What governments need to do now is convert the global agreement they have reached in Paris into national policies, including a progressive decarbonisation of the electricity generation sector. We have proposed that there should be 1000 GWe of nuclear new build by 2050 as part of a balanced low-carbon future energy mix. To achieve this, we need to see the introduction of energy markets with level playing fields which recognise the value of low carbon and reliable generation. We need to see the adoption of harmonised nuclear regulatory processes internationally. We also need to ensure that actions do not lead to clean nuclear power plants being closed prematurely and replaced with more polluting alternatives. Ongoing investment is also needed to help develop the next generation of nuclear technology, along with a clear and achievable pathway for deployment.”

Ahead of COP21, 188 nations had submitted their individual climate action plans, including how much they were intending to cut emissions. There is a wide range of targets in these Intended Nationally Determined Contributions (INDCs), from ambitious cuts by 2030 to almost doubling emissions by 2030, according to individual national circumstances. Collectively the INDCs, if met, are projected to result in a global temperature rise above pre-industrial levels of 2.7°C, which is considered insufficient constraint. National targets are not binding, there are no defined sanctions for failing to meet them, and they need verification anyway as well as five-yearly reviews ratcheting up the good intentions.

First stocktaking talks are planned for 2018. Countries with targets for 2025 should have new targets for 2020, while those with 2030 targets are invited to update them. This process is to be repeated every five years, with a first post-2020 review in 2023. The agreement requires countries regularly to update climate commitments, with each pledge being more ambitious than the last. It also invites countries to write long-term, mid-century low carbon emission strategies by 2020. In contrast to the Kyoto Protocol, the agreement binds all countries equally to these processes (but not targets), though developed countries are expected to “continue taking the lead by undertaking economy-wide absolute emission reduction targets.”

In the power sector, 70% of additional electricity generation to 2030 would be low-carbon. The full implementation of these pledges will require the energy sector to invest $13.5 trillion in energy efficiency and low-carbon technologies from 2015 to 2030, an annual average of $840 billion, according to the IEA. Excluded from all this is the role of forest and peat fires in contributing to emissions.

The Paris Agreement was made available in April 2016 for signature and ratification by individual countries. Following EU ratification, early in October 2016 it had been ratified by countries responsible for 55% of global greenhouse gas emissions, and by over 55 of the 197 signatories.  This implies consent to be bound by the terms of the Agreement. It will come into legal force, to the limited extent that is envisaged, on 4 November 2016. The USA and China - together representing 40% of global emissions - ratified the agreement together in early September.

"The entry into force of the Paris Agreement ... is an extraordinary political achievement which has opened the door to a fundamental shift in the way the world sees, prepares for, and acts on climate change through stronger action at all levels of government, business, investment and civil society," according to the UNFCCC. "The ratification of the Paris Agreement commits governments to making significant reductions in greenhouse gas emissions to limit the effects of climate change. This can only happen if we use all sources of low-carbon electricity, including nuclear energy," Agneta Rising, director general of the World Nuclear Association, said.

Group of 8 (G8)

The Group of 8 (Canada, France, Germany, Italy, Japan, the Russian Federation, the United Kingdom, and the USA) hold annual economic and political summit meetings of the heads of government with international officials.

The 2005 meeting held in Gleneagles, Scotland under the UK Presidency placed Climate Change and Africa as joint priority agenda items. Throughout the preceding year a series of events were held in preparation for the final summit in July.

In February 2005, the Scientific Conference on Climate Change was held at the Hadley Centre for Climate Research and Prediction in Exeter, where the latest scientific understanding of climate change was discussed. The proceedings of the meeting include a discussion of technology options, which recognises that the potential contribution of nuclear energy is almost without technical limits.

A ministerial roundtable meeting of Energy and Environment Ministers held in March 2005, involved 20 countries, including Brazil, China, India, Mexico and South Africa. The meeting concluded that the countries shared common goals of:

  • creating the conditions for economic development and poverty eradication by improving the accessibility and affordability of modern energy services;
  • providing security of supply with energy systems that are resilient, reliable and diversified; and
  • protecting local and global environmental quality, including addressing greenhouse gas emissions.

The Gleneagles Summit itself was distracted by other events and as a result limited progress was made in discussions on climate change. However, it was agreed that the topics of energy and climate change would continue to be discussed at future G8 meetings.

The meeting in St Petersburg, Russia in 2006 focused on global energy security and climate change. There was agreement that the G8 would take action in the following key areas:

  • Increasing transparency, predictability and stability of global energy markets;
  • Improving the investment climate in the energy sector;
  • Enhancing energy efficiency and energy saving;
  • Diversifying the energy mix;
  • Ensuring physical security of critical energy infrastructure;
  • Reducing energy poverty;
  • Addressing climate change and sustainable development.

Included in the details of what was proposed to address these key areas included an endorsement of nuclear energy: "Those of us who have or are considering plans relating to the use and/or development of safe and secure nuclear energy believe that its development will contribute to global energy security, while simultaneously reducing harmful air pollution and addressing the climate change challenge."

The agreement highlighted the INPRO project and the Generation IV International Forum, interim solutions to address back-end fuel cycle issues and the importance of independent effective regulation of nuclear installations. The agreement also highlighted the USA GNEP proposal and the complementary proposals by Russia and the IAEA.

Global energy security and climate change were discussed further at meetings in Germany (June 2007) and Japan (2008). Discussions also took place among the broader G20 group.

Europe

In many respects Europe has been a leader in promoting action on climate change, as set out in some detail above.

In March 2007 the European Council endorsed the European Commission's Strategic Energy Review and agreed on a unilateral cut of 20% in EU greenhouse gas emissions by 2020, relative to 1990 levels. The previous commitment was 8% reduction by 2012. This required strengthening and extending carbon trading arrangements as well as deploying low- or zero-carbon technology. The European Council also endorsed the objective of making a 30% reduction in greenhouse gas emissions by 2020 and said that it would commit to this 30% target if other developed countries committed to (unspecified) comparable reductions in emissions and the more advanced developing countries (e.g. India, Brazil, China) "contributed adequately according to their responsibilities and respective capabilities". French President Chirac described the outcome as "one of the great moments of European history."

The European Council also set a target of meeting 20% of EU energy needs from renewables by 2020, leaving individual countries to decide their own policies in such a way as to allow nuclear power as part of their energy mix to be taken into consideration in allocating individual country targets for renewables. The Council noted "the European Commission's assessment of the contribution of nuclear energy in meeting the growing concerns about safety of energy supply and CO2 emission reductions" and it acknowledged the role of nuclear energy "as a low CO2-emitting energy source." In the event the 2008 policy set was “20-20-20” – 20% reduction in CO2 emissions, 20% of electricity from renewables and 20% improvement in energy efficiency by 2020.

The European Commission’s 2030 Policy Framework for Climate and Energy in January 2014 moved away from major reliance on renewables to achieve emission reduction targets and allows scope for nuclear power to play a larger role. It is focused on CO2 emission reduction, not the means of achieving that, and allows more consideration for cost-effectiveness.

The centerpiece is a binding 40% reduction in domestic greenhouse gas emissions by 2030 (compared with a 1990 baseline) which will require strong commitments from EU member states. Current policies and measures if followed through should deliver 32% reduction by then, so 40% “is achievable” and widely supported. It implies a 43% cut from 2005 for CO2 in sectors covered by the EU emissions trading scheme (ETS). There are to be no post-2020 national renewables targets, and individual states are free to use whatever technology they wish to achieve emission reductions in the longer term, though a 27% “headline target at European level for renewable energy” is included. The framework also proposes reform of the ETS to make it the principal driver of climate policy (see Emission Trading section above), and it drops a binding energy efficiency target and a directive for use of biofuels in transport.

Impetus for the profound change in emphasis from the 2008 policy framework appears to have come from EU member states which are winding back renewables programs due to escalating costs. The International Energy Agency has pointed out the huge difference in energy prices between USA and EU, with gas prices three times as high and electricity twice as high in the EU. The EU is evidently concerned about loss of international competitiveness and the increasingly chaotic retreat from subsidy schemes related to its 2020 renewables target. More generally, it acknowledges that “the rapid development of renewable energy sources now poses new challenges for the energy system”.

The key change from 2020 goals is “providing flexibility for Member States to define a low-carbon transition appropriate to their specific circumstances, preferred energy mix and needs in terms of energy security, and allowing them to keep costs to a minimum.” An early test of this will be approval for UK plans to set long-term electricity prices to enable investment in nuclear plants.

The WNA said that the “flexible” approach outlined allows nuclear power to play an expanded role in decarbonising electricity supply. The ambitious target “is a bare minimum if the EU wishes to achieve its objective of an 80% reduction by 2050, and do its part in averting a 2°C rise in global temperatures. Unfortunately the target of 27% for renewable energy continues to undermine the possibility for cost efficiency in meeting the carbon target. It also again demonstrates an unjustified preference in EU policy for renewable energy over other carbon reduction pathways – such as nuclear energy – regardless of cost, maturity and the preferences of individual Member States.”

However, only weeks later the EU parliament in a non-binding resolution voted by 341 to 263 to claw back some of the previous provisions by changing the EC draft policy to call for binding national targets of 30% of power from renewables (not 27% overall) and reinstating the energy efficiency goal to 40% improvement by 2030, along with the EC 40% greenhouse gas reduction. Member states can however go with the EC draft policy rather than this.

Asia Pacific Partnership (APP)

The Asia-Pacific Partnership on Clean Development and Climate, known informally as APP, is a non-treaty partnership established by Australia, India, Japan, China, South Korea and the United States in July 2005 and launched in 2006. The Partnership involved countries that account for about half of the world's population and more than half of the world's economy, energy use, and greenhouse gas emissions. In October 2007, Canada joined APP.

The objectives of the partnership included:

  • To work together and with private companies to expand markets for investment and trade in cleaner, more efficient energy technologies, goods, and services in key sectors.
  • To work with multilateral development banks on financing for initiatives and programs identified by the task forces that will expand the use of technologies and practices designed to promote objectives of the Partnership.
  • To work on areas of collaboration including Energy Efficiency, Methane Capture and Use, Rural/Village Energy Systems, Clean Coal, Civilian Nuclear Power, Advanced Transportation, Liquefied Natural Gas, Geothermal, Building and Home Construction/Operation, Bioenergy, Agriculture/Forestry, Hydropower, Wind Power and Solar Power.

In April 2011 the APP wound up, though some programs continued under other auspices. The APP Power Generation and Transmission Task Force was transitioned into a new "Global Superior Energy Performance Partnership (GSEP)" that will form part of the Clean Energy Ministerial that had been established in 2010. The Clean Energy Ministerial initiative includes representatives from 24 governments representing 70% of global GDP and 80% of global greenhouse gas emissions.

Contraction & Convergence

The concept of Contraction and Convergence is a long-term framework towards the ultimate object of climate change policy in terms of 'safe' emissions levels. The concept has gained some interest amongst politicians and climate change experts and is seen as potentially superseding the arbitrary short-term target setting of the current Kyoto Protocol process.

Under a Contraction and Convergence regime an international agreement would define to what level atmospheric greenhouse gas concentrations could rise before becoming unacceptable. Once this is defined, an estimate would be made of how much reduction in global greenhouse gas emissions is required to meet the target, taking into account the effect of sinks, and how quickly the target should be reached. This represents the 'contraction' element, and in itself it does not differ substantially from the aims of the UNFCCC to stabilize "greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system."

The key differentiating factor of Contraction and Convergence is the proposal that ultimately the 'right' to emit carbon dioxide is a human right which should be shared equally. Therefore, emissions targets should ultimately be allocated to countries on the basis of their populations. Emissions rights would be on a per capita basis and therefore require convergence from the present very unequal per capita levels to a universal per capita level.

During the convergence period, which should not be protracted, emission permits would be progressively adjusted from status quo to these new levels. Permits could be traded, and this would cause a major economic transfer from countries that have used fossil fuels to create wealth to those still struggling to alleviate poverty. After convergence, each country would receive the same allocation of carbon dioxide emission rights per head of population and further trading in permits is envisaged.

The fundamental principles of Contraction and Convergence have received some support from those who see the equal allocation of emissions rights as promoting social equity. However, these fundamental principles alone do not provide an alternative to the UNFCCC process, as they are no more than conceptual and much would be needed to turn them into a policy framework. Achieving political backing in developed countries is unlikely.

There are also concerns as to the fairness of the proposal. There are concerns that countries with rapidly expanding populations could be rewarded through this scheme, as their expanding populations could result in them having a greater allocation of emissions on a country basis. It might therefore be necessary to fix the overall country allocation on a specific national population on a specific date.

It has also been suggested that some countries have conditions that inherently require greater energy usage and consequent emissions, so therefore there should be differentiated emissions rights depending on local circumstances. For example someone living in the Arctic would have greater energy needs for heating and lighting than someone living in a more temperate region.

Carbon emission stocktake

The first complete set of data for the 41 industrialised parties of the UN Framework Convention on Climate Change (FCCC) was released at the Nairobi meeting and shows that greenhouse gas emissions continued to rise despite measures under the Kyoto Protocol. Figures for 1990 to 2004 showed that apart from the temporary effect of restructuring in eastern Europe, emissions from industrialised countries rose 11% over the period. For all those countries emissions were down by 3% and for the 36 parties to the Protocol, emissions declined by 15%. Emissions from the USA were 16% up, those from Australia 25% up, and energy-related CO2 emissions for China rose 110% and for India 89% over the period – those from China exceeding Europe's. Most developed countries were targeting an 8% reduction to 2008-12.

In May 2011 the OECD International Energy Agency (IEA) released figures for 2010 energy-related CO2 emissions, which reached a new high of 30.6 billion tonnes. The previous record was 29.3 Gt in 2008 (emissions in 2009 dipped because of the global financial crisis).  Non-OECD countries – particularly China and India – saw much stronger increases in emissions as their economic growth accelerated. On a per capita basis, OECD countries emitted an average of 10 tonnes of CO2, compared with 5.8 tonnes in China and 1.5 tonnes in India. In terms of fuel, some 44% of the estimated CO2 emissions in 2010 came from the burning of coal, 36% from oil, and 20% from natural gas. The IEA estimated that some 80% of projected CO2 emissions from the power sector in 2020 were already 'locked in', as they will come from either existing power plants or plants currently under construction.

CO2 emissions in 2014 were 35.7 billion tonnes, including 10.5 Gt from China, 5.3 Gt from the USA, 3.4 Gt from the EU, and 2.3 Gt from India.

 

Apart from policies to use low or zero-carbon sources for electricity generation, some countries have favoured the use of natural gas to replace coal, on the basis that emissions from actually burning the fuel are around half of those from coal. However, methane leakage from the drilling and pipeline delivery of natural gas can offset any CO2 benefits that natural gas may bring over coal during combustion and use. A 3% leakage of natural gas will push the global warming effect of natural gas used for electricity to the same level as that of coal per kWh.

  • Nuclear power is cost competitive with other forms of electricity generation, except where there is direct access to low-cost fossil fuels.
  • Fuel costs for nuclear plants are a minor proportion of total generating costs, though capital costs are greater than those for coal-fired plants and much greater than those for gas-fired plants.
  • Providing incentives for long-term, high-capital investment in deregulated markets driven by short-term price signals presents a challenge in securing a diversified and reliable electricity supply system.
  • In assessing the economics of nuclear power, decommissioning and waste disposal costs are fully taken into account.
  • Nuclear power plant construction is typical of large infrastructure projects around the world, whose costs and delivery challenges tend to be under-estimated.

Assessing the relative costs of new generating plants utilising different technologies is a complex matter and the results depend crucially on location. Coal is, and will probably remain, economically attractive in countries such as China, the USA and Australia with abundant and accessible domestic coal resources as long as carbon emissions are cost-free. Gas is also competitive for base-load power in many places, particularly using combined-cycle plants.

Nuclear power plants are expensive to build but relatively cheap to run. In many places, nuclear energy is competitive with fossil fuels as a means of electricity generation. Waste disposal and decommissioning costs are included in the operating costs. If the social, health and environmental costs of fossil fuels are also taken into account, the economics of nuclear power are outstanding.

On a levelised (i.e. lifetime) basis, nuclear power is an economic source of electricity generation, combining the advantages of security, reliability, very low greenhouse gas emissions and cost competitiveness in many markets. Existing plants function well with a high degree of predictability. The operating cost of these plants is lower than almost all fossil fuel competitors, with a very low risk of operating cost inflation. Plants are now expected to operate for 60 years and even longer in the future. The main economic risks to existing plants lie in the impacts of subsidised intermittent renewable and low-cost gas-fired generation. The political risk of higher, specifically-nuclear, taxation adds to these risks.

Assessing the costs of nuclear power

The economics of nuclear power involves consideration of several aspects:

Capital costs, which include the cost of site preparation, construction, manufacture, commissioning and financing a nuclear power plant. Building a large-scale nuclear reactor takes thousands of workers, huge amounts of steel and concrete, thousands of components, and several systems to provide electricity, cooling, ventilation, information, control and communication. To compare different power generation technologies the capital costs must be expressed in terms of the generating capacity of the plant (for example as dollars per kilowatt). Capital costs may be calculated with the financing costs included or excluded. If financing costs are included then the capital costs change in proportion to the length of time it takes to build and commission the plant and with the interest rate or mode of financing employed. It is normally termed the ‘investment cost’. If the financing costs are excluded from the calculation the capital costs is called the ‘overnight cost’, because it imagines that the plant appeared fully built overnight.

Plant operating costs, which include the costs of fuel, operation and maintenance (O&M), and a provision for funding the costs of decommissioning the plant and treating and disposing of used fuel and wastes. Operating costs may be divided into ‘fixed costs’ that are incurred whether or not the plant is generating electricity and ‘variable costs’, which vary in relation to the output. Normally these costs are expressed relative to a unit of electricity (for example, cents per kilowatt-hour) to allow a consistent comparison with other energy technologies. To calculate the operating cost of a plant over its whole life (including the costs of decommissioning and used fuel and waste management), we must estimate the ‘levelised’ cost at present value. It represents the price that the electricity must fetch if the project is to break even (after taking account of the opportunity cost of capital through the application of a discount rate).

External costs to society from the operation, which in the case of a nuclear power is usually assumed to be zero, but could include the costs of dealing with a serious accident that are beyond the insurance limit and in practice need to be picked up by the government. The regulations that control nuclear power typically require the plant operator to make a provision for disposing of any waste, thus these costs are ‘internalised’ (and are not external). Electricity generation from fossil fuels is not regulated in the same way, and therefore the operators of such thermal power plants do not yet internalise the costs of greenhouse gas emission or of other gases and particulates released into the atmosphere. Including these external costs in the calculation gives nuclear power a significant advantage over fossil fuelled electricity generation.

Considering these costs in turn, with information from numerous studies:

Capital cost

Construction costs comprise several things: the bare plant cost (usually identified as engineering-procurement-construction – EPC – cost), the owner's costs (land, cooling infrastructure, administration and associated buildings, site works, switchyards, project management, licences, etc.), cost escalation and inflation. Owner's costs may include some transmission infrastructure. Recent studies have shown an increase in the capital cost of building both conventional and nuclear power plants.

The term 'overnight capital cost' is often used, meaning EPC plus owners’ costs and excluding financing, escalation due to increased material and labour costs, and inflation. Construction cost – sometimes called 'all-in cost' – adds to overnight cost any escalation and interest during construction and up to the start of construction. It is expressed in the same units as overnight cost and is useful for identifying the total cost of construction and for determining the effects of construction delays. In general the construction costs of nuclear power plants are significantly higher than for coal- or gas-fired plants because of the need to use special materials, and to incorporate sophisticated safety features and back-up control equipment. These contribute much of the nuclear generation cost, but once the plant is built the cost variables are minor. About 80% of overnight costs are EPC costs, with about 70% of these consisting of direct (physical plant equipment with labour and materials to assemble them) and 30% indirect (supervisory engineering and support labour costs with some materials) costs. The remaining 20% of overnight costs are contingencies and owners’ costs (essentially the cost of testing systems and training staff).

The OECD Nuclear Energy Agency’s (NEA) calculation of the overnight cost for a nuclear power plant built in the OECD rose from about $1,900/kWe at the end of the 1990s to $3,850/kWe in 2009. In the 2015 edition of its report on Projected Costs of Generating Electricity, the overnight costs in OECD countries ranged from $2021/kWe in Korea to $6215/kWe in Hungary. For China, two comparable figures were $1807/kWe and $2615/kWe.

The NEA figures for the 1990s must be treated with caution as they are not in line with some other data sources. The US Energy Information Administration (EIA) calculated that, in constant 2002 values, the realized real overnight cost of a nuclear power plant built in the USA grew from US$ 1,500/kWe in the early 1960s to US$ 4,000/kWe in the mid-1970s. The EIA cited increased regulatory requirements (including design changes that required plants to be back-fitted with modified equipment), licensing problems, project management problems and mis-estimation of costs and demand as the factors contributing to the increase during the 1970s. Its 2010 reportUpdated Capital Cost Estimates for Electricity Generation Plants, gave an estimate for a new nuclear plant of US$ 5,339/kW.

There is also significant variation of capital costs by country, particularly between the emerging industrial economies of East Asia and the mature markets of Europe and North America, which has a variety of explanations, including differential labour costs, more experience in the recent building of reactors, economies of scale from building multiple units and streamlined licensing and project management within large civil engineering projects. With few new orders, the data set for new build costs is lacking. The shift to Generation III reactors has added further uncertainty. Other non-nuclear generation technologies also show variation and as do major infrastructure projects such as roads and bridges, depending upon where they are built. However, the variation is particularly crucial for electricity generation as its economics depend so much on minimising its capital investment cost which must be passed onto consumers, unlike roads, bridges and dams which usually have less complexity. Large infrastructure projects of all kinds tend to be over-budget and late in most parts of the world according to research by the University of Lincoln (UK) and the Megaproject database.

The French national audit body, the Cour des comptes, said in 2012 that the overnight capital costs of building NPPs increased over time from € 1,070/kWe (at 2010 prices) when the first of the 50 PWRs was built at Fessenheim (commissioned in 1978) to € 2,060/kWe when Chooz 1 and 2 were built in 2000, and to a projected € 3,700/kWe for the Flamanville EPR. It can be argued that much of this escalation relates to the smaller magnitude of the programme by 2000 (compared with when the French were commissioning 4-6 new PWRs per year in the 1980s) and to the subsequent loss of economies of scale.

In several countries, notably the UK, there is a trend to greater vendor involvement in financing projects, but with an intention to relinquish equity once the plant is running.

A presentation by Dr. N. Barkatullah, UAE Regulation & Supervision Bureau, at the World Nuclear Association 2014 Symposium showed the risk in construction costs (per kilowatt of capacity), much of it due to financing cost incurred by delays:

Challenge: Construction Risk

The same presentation showed the following ranges of figures for overnight capital cost in different parts of the world:

Challenge: NPP investment cost uncertainty

The IEA-NEA Nuclear Energy Roadmap 2015 estimates China’s average overnight costs of approximately USD 3,500/kW are more than a third less than that in the EU of USD 5,500/kW. Costs in the US are about 10% lower than the EU, but still 30% higher than in China and India, and 25% above South Korea. In its main scenario, 2050 assumptions for overnight costs of nuclear in the United States and European Union are estimated to decline somewhat, reaching levels closer to those in the Republic of Korea, while costs in Asia are assumed to remain flat.

In China it is estimated that building two identical 1000 MWe reactors on a site can result in a 15% reduction in the cost per kW compared with that of a single reactor.

Financing costs will depend on the rate of interest on debt, the debt-equity ratio, and if it is regulated, how the capital costs are recovered. There must also be an allowance for a rate of return on equity, which is risk capital.

Long construction periods will push up financing costs, and in the past they have done so spectacularly. In Asia construction times have tended to be shorter, for instance the new-generation 1300 MWe Japanese reactors which began operating in 1996 and 1997 were built in a little over four years, and 48 to 54 months is typical projection for plants today. The last three South Korean reactors not delayed by cabling replacement averaged 51 months construction time. See also Construction Risk graphic above.

An insight on the relationship among ingredients of capital cost was provided by testimony to a Georgia Public Service Commission hearing concerning the Vogtle 3&4 project in June 2014. Here, for Georgia Power‘s 45.7% share, EPC cost was $3.8 billion, owners cost $0.6 billion, and financing cost $1.7 billion if completed 2016-17. The cost of possible delayed completion was put at $1.2 million per day. This puts the total cost of the project at about $14 billion.

The conclusion of a study published in 2016 on the Historical construction costs of global nuclear power reactors,* presented a new data set for overnight nuclear construction costs across seven countries. Some conclusions emerged that are in contrast to the past literature. While several countries, notably the USA, show increasing costs over time, other countries show more stable costs in the longer term, and cost declines over specific periods in their technological history. One country, South Korea, experiences sustained construction cost reductions throughout its nuclear power experience. The variations in trends show that the pioneering experiences of the USA or even France are not necessarily the best or most relevant examples of nuclear cost history. These results showed that there is no single or intrinsic learning rate expected for nuclear power technology, nor any expected cost trend. How costs evolve over time appears to be dependent on several different factors. The large variation in cost trends over time and across different countries – even with similar nuclear reactor technologies – suggests that cost drivers other than learning-by-doing have dominated the experience of nuclear power construction and its costs. Factors such as utility structure, reactor size, regulatory regime, and international collaboration may have a larger effect. Therefore, drawing any strong conclusions about future nuclear power costs based on one country's experience – especially the US experience in the 1970s and 1980s – would be ill-advised.

* Lovering, J.R., Yip, A, Nordhaus, Ted, in Energy Policy 91, 371-382 (April 2016)

Operating costs

Fuel costs have from the outset given nuclear energy an advantage compared with coal, oil and gas-fired plants. Uranium, however, has to be processed, enriched and fabricated into fuel elements, and about half of the cost is due to enrichment and fabrication. In the assessment of the economics of nuclear power allowances must also be made for the management of radioactive used fuel and the ultimate disposal of this used fuel or the wastes separated from it. But even with these included, the total fuel costs of a nuclear power plant in the OECD are typically about a third of those for a coal-fired plant and between a quarter and a fifth of those for a gas combined-cycle plant. The US Nuclear Energy Institute suggests that for a coal-fired plant 78% of the cost is the fuel, for a gas-fired plant the figure is 89%, and for nuclear the uranium is about 14%, or double that to include all front end costs.

In July 2015, the approx. US $ cost to get 1 kg of uranium as UO2 reactor fuel (at current long-term uranium price):

Uranium: 8.9 kg U3O8 x $97 US$ 862 46%
Conversion: 7.5 kg U x $16 US$ 120 6%
Enrichment: 7.3 SWU x $82 US$ 599 32%
Fuel fabrication: per kg (approx) US$ 300 16%
Total, approx:   US$ 1880  

At 45,000 MWd/t burn-up this gives 360,000 kWh electrical per kg, hence fuel cost: 0.52 ¢/kWh.

Fuel costs are one area of steadily increasing efficiency and cost reduction. For instance, in Spain the nuclear electricity cost was reduced by 29% over 1995-2001. This involved boosting enrichment levels and burn-up to achieve 40% fuel cost reduction. Prospectively, a further 8% increase in burn-up will give another 5% reduction in fuel cost.

Uranium has the advantage of being a highly concentrated source of energy which is easily and cheaply transportable. The quantities needed are very much less than for coal or oil. One kilogram of natural uranium will yield about 20,000 times as much energy as the same amount of coal. It is therefore intrinsically a very portable and tradable commodity.

The contribution of fuel to the overall cost of the electricity produced is relatively small, so even a large fuel price escalation will have relatively little effect (see below). Uranium is abundant and widely available.

There are other possible savings. For example, if used fuel is reprocessed and the recovered plutonium and uranium is used in mixed oxide (MOX) fuel, more energy can be extracted. The costs of achieving this are large, but are offset by MOX fuel not needing enrichment and particularly by the smaller amount of high-level wastes produced at the end. Seven UO2 fuel assemblies give rise to one MOX assembly plus some vitrified high-level waste, resulting in only about 35% of the volume, mass and cost of disposal.

Operating costs include operating and maintenance (O&M) plus fuel. Fuel cost figures include used fuel management and final waste disposal. These costs, while usually external for other technologies, are internal for nuclear power (i.e. they have to be paid or set aside securely by the utility generating the power, and the cost passed on to the customer in the actual tariff).

This 'back end' of the fuel cycle, including used fuel storage or disposal in a waste repository, contributes up to 10% of the overall costs per kWh – rather less if there is direct disposal of used fuel rather than reprocessing. The $26 billion US used fuel program is funded by a 0.1 cent/kWh levy.

Decommissioning costs are about 9-15% of the initial capital cost of a nuclear power plant. But when discounted, they contribute only a few percent to the investment cost and even less to the generation cost. In the USA they account for 0.1-0.2 cent/kWh, which is no more than 5% of the cost of the electricity produced.

System costs

System costs are the total costs above plant-level costs (capital and operating) to supply electricity at a given load and given level of security of supply. They include grid connection, extension and reinforcement, short-term balancing costs and long-term costs of maintaining adequate back-up.

They are external to the building and operation of any power plant, but must be paid by the electricity consumer, usually as part of the transmission and distribution cost. From a government policy point of view they are just as significant as the actual generation cost, but are seldom factored in to comparisons among different supply options, especially comparing base-load with dispersed variable renewables. In fact that the total system cost should be analysed when introducing new power generating capacity on the grid. Any new power plant likely requires changes to the grid, and hence incurs a significant cost for power supply that must be accounted for. But this cost for large base-load plants is small compared with integrating variable renewables to the grid.

The integration of intermittent renewable supply on a preferential basis despite higher unit cost creates significant diseconomies for dispatchable supply, as is now becoming evident in Germany, Austria and Spain, compromising security of supply and escalating costs. At 40% share of electricity being from renewables, the capital cost component of power from conventional thermal generation sources increases substantially as their capacity factor decreases – the utilisation effect. This has devastated the economics of some gas-fired plants in Germany, for instance.

The overall cost competitiveness of nuclear, as measured on a levelised basis (see figures below on comparison of LCOE and system costs), is much enhanced by its modest system costs. However, the impact of intermittent electricity supply on wholesale markets has a profound effect on the economics of base-load generators, including nuclear, that is not captured in the levelised cost comparisons given by the IEA/NEA reports. The negligible marginal operating costs of wind and solar means that, when climatic conditions allow generation from these sources, they undercut all other electricity producers. At high levels of renewable generation, e.g. as implied by the EU’s 30% renewable penetration target, the nuclear load factor is reduced and the volatility of wholesale prices greatly increased whilst the average wholesale price level falls. The increased penetration of intermittent renewables thereby greatly reduces the financial viability of nuclear generation in wholesale markets where intermittent renewable energy capacity is significant. The integration of intermittent renewables with conventional base-load generation is a major challenge facing policymakers in the EU and certain states in the USA, and until this challenge is resolved, e.g. by the introduction of long-term capacity markets or power purchase agreements, then investment in base-load generation capacity in these markets is likely to remain insufficient.

An OECD study found that the integration of large shares of intermittent renewable electricity is a major challenge for the electricity systems of OECD countries and for dispatchable generators such as nuclear. Grid-level system costs for variable renewables are large ($15-80/MWh) but depend on country, context and technology (onshore wind < offshore wind < Solar PV). Nuclear system cost is $1-3/MWh.

See also paper on Electricity Transmission Grids

External costs

External costs are not included in the building and operation of any power plant, and are not paid by the electricity consumer, but by the community generally. The external costs are defined as those actually incurred in relation to health and the environment, and which are quantifiable but not built into the cost of the electricity.

The report of a major European study of the external costs of various fuel cycles, focusing on coal and nuclear, was released in mid 2001 – ExternE. It shows that in clear cash terms nuclear energy incurs about one-tenth of the costs of coal. If these costs were in fact included, the EU price of electricity from coal would double and that from gas would increase 30%. These are without attempting to include the external costs of global warming.

The European Commission launched the project in 1991 in collaboration with the US Department of Energy, and it was the first research project of its kind "to put plausible financial figures against damage resulting from different forms of electricity production for the entire EU". The methodology considers emissions, dispersion and ultimate impact. With nuclear energy the risk of accidents is factored in along with high estimates of radiological impacts from mine tailings (waste management and decommissioning being already within the cost to the consumer). Nuclear energy averages 0.4 euro cents/kWh, much the same as hydro, coal is over 4.0 cents (4.1-7.3), gas ranges 1.3-2.3 cents and only wind shows up better than nuclear, at 0.1-0.2 cents/kWh average. NB these are the external costs only.

A further study commissioned by the European Commission in 2014 and carried out by the Ecofys consultancy calculated external costs for nuclear as €18-22/MWh, including about €5/MWh for health impacts, €4/MWh for accidents and €12/MWh for so-called ‘resource depletion’, relating to the “costs to society of consumption of finite fuel resources now, rather than in the future.” Although Ecofys acknowledged that the resource depletion cost is difficult to calculate since the scarcity of a finite natural resource is already reflected in its market price, and could therefore just as well be zero, a high estimate was asserted using questionable methodology and without taking account of the potential for recycling nuclear fuel.

Another report for the European Commission made by Professor William D’haeseleer, University of Leuven, in November 2013, estimated the cost of a potential nuclear accidents to be in a range of €0.3-3/MWh.

Tax costs

In several EU countries, nuclear power generation is specifically taxed without environmental justification. In 2012 Belgium raised some €479 million from a €0.005/kWh tax, in France €350 million from a tax on nuclear plants, in Germany €1400 million from a fuel tax, in Sweden €424 million from a nuclear tax of €0.0067/kWh, and in the UK €427 million from €0.0061/kWh climate change levy. The total was about €3 billion per year.

See also paper on Energy subsidies and external costs.

Comparing the economics of different forms of electricity generation

In 2013 the US Energy Information Administration published figures for the average levelized costs per unit of output for generating technologies to be brought on line in 2018, as modeled for its Annual Energy Outlook. These show advanced nuclear, natural gas (advanced combustion turbine), and conventional coal in the bracket 10-11c/kWh. Combined cycle natural gas is 6.6 cents, advanced coal with CCS 13.6 cents, and among the non-dispatchable technologies: wind onshore 8.7 cents, solar PV 14.4 cents, offshore wind 22.2 cents and solar thermal 26.2 c/kWh. The actual capital cost of nuclear is about the same as coal, and very much more than any gas option.

The 2015 edition of the OECD study on Projected Costs of Generating Electricity showed that the range for levelised cost of electricity (LCOE) varied much more for nuclear than coal or CCGT with different discount rates, due to it being capital-intensive. The nuclear LCOE is largely driven by capital costs. At 3% discount rate, nuclear was substantially cheaper than the alternatives in all countries, at 7% it was comparable with coal and still cheaper than gas, at 10% it was comparable with both. At low discount rates it was much cheaper than wind and PV. Based on a 0% discount rate, LCOE for nuclear soared to three times as much as the 10% discount rate, while that for coal was 1.4 times and for CCGT it changed very little. Solar PV increased 2.25 times and onshore wind nearly twice at 10% discount rate, albeit with very different capacity factors to the 85% for the three base-load options. For all technologies, a $30 per tonne carbon price was included. LCOE figures omit system costs.

Comparative LCOEs and System Costs in Four Countries (2014 and 2012)

* LCOE plant costs have been taken from Projected Costs of Generating Electricity 2015 Edition. System costs have been taken fromNuclear Energy and Renewables (NEA, 2012). A 30% generation penetration level for onshore wind, offshore wind and solar PV has been assumed in the NEA estimates of system costs, which include back-up costs, balancing costs, grid connection, extension and reinforcement costs. A discount rate of 7% is used throughout, which is therefore consistent with the plant level LCOE estimates given in the 2015 edition of Projected Costs of Generating Electricity. The 2015 study applies a $30/t CO2 price on fossil fuel use and uses 2013 US$ values and exchange rates.

Projected nuclear LCOE costs for plants built 2015-2020, $/MWh

Country At 3% discount rate At 7% discount rate At 10% discount rate
Belgium 51.5 84.2 116.8
Finland 46.1 77.6 109.1
France 50.0 82.6 115.2
Hungary 53.9 89.9 125.0
Japan 62.6 87.6 112.5
South Korea 28.6 40.4 51.4
Slovakia 53.9 84.0 116.5
UK 64.4 100.8 135.7
USA 54.3 77.7 101.8
China 25.6-30.8 37.2-47.6 48.8-64.4

Source: OECD/IEA-NEA, Projected Costs of Generating Electricity, 2015 Edition, Table 3.11, assuming 85% capacity factor

Overnight capital costs for nuclear technologies in OECD countries ranged from $2021 per kWe of capacity (in South Korea) to $6125 per kWe (in Hungary) in the 2015 report.

Rosatom claimed in November 2015 that due to its integrated structure, the LCOE of new VVER reactors exported is no more than $50-$60 per MWh in most countries.

The 2010 edition of the report had noted a significant increase in costs of building base-load plants over the previous five years. The 2015 report shows that this increase has stopped, and that this is particularly significant for nuclear technologies, "undermining the growing narrative that nuclear costs continue to increase globally."

The 2010 edition of Projected Costs of Generating Electricity set out some actual costs of electricity generation, showing nuclear as very competitive at 5% discount rate, especially if CCS was added to fossil fuel sources, but much less so at 10% (details in section below on Major studies on future cost competitiveness).

It is important to distinguish between the economics of nuclear plants already in operation and those at the planning stage. Once capital investment costs are effectively “sunk”, existing plants operate at very low costs and are effectively “cash machines”. Their operations and maintenance (O&M) and fuel costs (including used fuel management) are, along with hydropower plants, at the low end of the spectrum and make them very suitable as base-load power suppliers. This is irrespective of whether the investment costs are amortized or depreciated in corporate financial accounts – assuming the forward or marginal costs of operation are below the power price, the plant will operate.

US figures for 2012 published by NEI show the general picture, with nuclear generating power at 2.40 c/kWh, compared with coal at 3.27 cents and gas at 3.40 cents.

 

U.S. Electricity Production Costs, 1995-2012 line graph

Note: the above data refer to fuel plus operation and maintenance costs only, they exclude capital, since this varies greatly among utilities and states, as well as with the age of the plant.

A Finnish study in 2000 also quantified fuel price sensitivity to electricity costs:
 

The Impact of Fuel Costs on Electricity Generation Costs line graph

These show that a doubling of fuel prices would result in the electricity cost for nuclear rising about 9%, for coal rising 31% and for gas 66%. Gas prices have since risen significantly.

The impact of varying the uranium price in isolation is shown below in a worked example of a typical US plant, assuming no alteration in the tails assay at the enrichment plant.

Effect of Uranium Price on Fuel Cost line graph

Doubling the uranium price (say from $25 to $50 per lb U3O8) takes the fuel cost up from 0.50 to 0.62 US cents per kWh, an increase of one quarter, and the expected cost of generation of the best US plants from 1.3 US cents per kWh to 1.42 cents per kWh (an increase of almost 10%). So while there is some impact, it is comparatively minor, especially by comparison with the impact of gas prices on the economics of gas generating plants. In these, 90% of the marginal costs can be fuel. Only if uranium prices rise to above $100 per lb U3O8 ($260 /kgU) and stay there for a prolonged period (which seems very unlikely) will the impact on nuclear generating costs be considerable.

Nevertheless, for nuclear power plants operating in competitive power markets where it is impossible to pass on any fuel price increases (ie the utility is a price-taker), higher uranium prices will cut corporate profitability. Yet fuel costs have been relatively stable over time – the rise in the world uranium price between 2003 and 2007 added to generation costs, but conversion, enrichment and fuel fabrication costs did not followed the same trend.

In February 2014 the US Nuclear Energy Institute presented figures from the Electric Utility Cost Group on US generating costs comprising fuel, capital and operating costs for 61 nuclear sites in 2012. The average came to $44/MWh, being $50.54 for single-unit plants and $39.44 for multi-unit plants (all two-unit except Browns Ferry, Oconee and Palo Verde). The $44 represented a 58% increase in ten years, largely due to a threefold increase in capital expenditure on plants which were mostly old enough to be fully depreciated. Over half of the capital expenditure (51%) in 2012 related to power uprates and licence renewals, while 26% was for equipment replacement.

For prospective new nuclear plants, the fuel component is even less significant (see below). The typical front end nuclear fuel cost is typically only 15-20% of the total, as opposed to 30-40% for operating nuclear plants.

Competitiveness in the context of increasing use of power from renewable sources, which are legally preferred, is a major issue today. The most important renewable sources are intermittent by nature, which means that their supply to the electricity system does not necessarily match demand from customers. In power grids where renewable sources of generation make a significant contribution, intermittency forces other generating sources to ramp up their supply or power down at short notice. This volatility can have a large impact on non-intermittent generators’ profitability.A variety of responses to the challenge of intermittent generation are possible. Two options currently being implemented are increased conventional plant flexibility and increased grid capacity and coverage. Flexibility is seen as most applicable to gas and coal fired generators, but nuclear reactors, normally regarded as base-load producers, also have the ability to load-follow, eg, by the use of ‘grey rods’ to modulate the reaction speed.

As the scale of intermittent generating capacity increases however, more significant measures will be required. The establishment and extension of capacity mechanisms, which offer payments to generators prepared to guarantee supply for defined periods, are now under serious consideration within the EU. Capacity mechanisms can in theory provide security of supply to desired levels but at a price which might be high, for example, Morgan Stanley has estimated that investors in a 800 MWe gas plant providing for intermittent generation would require payments of €80 million per year whilst Ecofys calculate that a 4 GWe reserve in Germany would cost €140-240/year. Almost by definition, investors in conventional plant designed to operate intermittently will face low and uncertain load factors and will therefore demand significant capacity payments in return for the investment decision. In practice, until the capacity mechanism has been reliably implemented, investors are likely to withhold investment. Challenges for EU power market integration are expected to result from differences between member state capacity mechanisms.

The 2014 Ecofys report for the European Commission on Subsidies and Costs of EU Energy purported to present a complete and consistent set of data on electricity generation and system costs, as well as external costs and interventions by governments to reduce costs to consumers. The report attributed €6.96 billion to nuclear power in the EU in 2012, including €4.33 billion decommissioning costs (shortfall from those already internalised). Geographically the total broke down to include EU support of €3.26 billion, and UK €2.77 billion, which was acknowledged as including military legacy clean-up. Consequently there are serious questions about the credibility of such figures.

Economic implications of particular plants

Apart from considerations of cost of electricity and the perspective of an investor or operator, there are studies on the economics of particular generating plants in their local context.

Early in 2015 a study, Economic Impacts of the R.E. Ginna Nuclear Power Plant, was prepared by the US Nuclear Energy Institute. It analyzes the impact of the 580 MWe PWR plant’s operations through the end of its 60-year operating licence in 2029. It generates an average annual economic output of over $350 million in western New York state and an impact on the U.S. economy of about $450 million per year. Ginna employs about 700 people directly, adding another 800 to 1,000 periodic jobs during reactor refueling and maintenance outages every 18 months. Annual payroll is about $100 million. Secondary employment involves another 800 jobs. Ginna is the largest taxpayer in the county. Operating at more than 95% capacity factor, it is a very reliable source of low-cost electricity. Its premature closure would be extremely costly to both state and country – far in excess of the above figures.

In June 2015 a study, Economic Impacts of the Indian Point Energy Center, was published by the US Nuclear Energy Institute, analyzing the economic benefits of Entergy’s Indian Point 2&3 reactors in New York state (1020 and 1041 MWe net). It showed that they annually generate an estimated $1.6 billion in the state and $2.5 billion across the nation as a whole. This includes about $1.3 billion per year in the local counties around the plant. The facility contributes about $30 million in state and local property taxes and has an annual payroll of about $140 million for the plant’s nearly 1,000 employees. The total tax benefit to the local, state and federal governments from the plant is about $340 million per year, and the plant’s direct employees support another 5,400 indirect jobs in New York state and 5,300 outside it. It also makes a major contribution to grid reliability and prevents the release of 8.5 million tonnes of CO2 per year.

In September 2015 a Brattle Group report said that the five nuclear facilities in Pennsylvania contribute $2.36 billion annually to the state's gross domestic product and account for 15,600 direct and secondary full-time jobs.

Future cost competitiveness

Understanding the cost of new generating capacity and its output requires careful analysis of what is in any set of figures. There are three broad components: capital, finance and operating costs. Capital and financing costs make up the project cost.

Calculations of relative generating costs are made using levelised costs, meaning average costs of producing electricity including capital, finance, owner's costs on site, fuel and operation over a plant's lifetime, with provision for decommissioning and waste disposal.

It is important to note that capital cost figures quoted by reactor vendors, or which are general and not site-specific, will usually just be for EPC costs. This is because owner's costs will vary hugely, most of all according to whether a plant is Greenfield or at an established site, perhaps replacing an old plant.

There are several possible sources of variation which preclude confident comparison of overnight or EPC (Engineering, Procurement & Construction) capital costs – eg whether initial core load of fuel is included. Much more obvious is whether the price is for the nuclear island alone (Nuclear Steam Supply System) or the whole plant including turbines and generators – all the above figures include these. Further differences relate to site works such as cooling towers as well as land and permitting – usually they are all owner's costs as outlined earlier in this section. Financing costs are additional, adding typically around 30%, and finally there is the question of whether cost figures are in current (or specified year) dollar values or in those of the year in which spending occurs.

The 2015 edition of the OECD study on Projected Costs of Generating Electricity considered the cost and deployment perspectives for small modular reactors (SMRs) and Generation IV reactor designs – including very high temperature reactors and fast reactors – that could start being deployed by 2030. Although it found that the specific per-kWe costs of SMRs are likely to be 50% to 100% higher than those for large Generation III reactors, these could be offset by potential economies of volume from the manufacture of a large number of identical SMRs, plus lower overall investment costs and shorter construction times that would lower the capital costs of such plants. "SMRs are expected at best to be on a par with large nuclear if all the competitive advantages … are realised," the report noted.

Major studies on future cost competitiveness

There have been many studies carried out examining the economics of future generation options, and the following are merely the most important and also focus on the nuclear element.

A May 2016 draft declaration related to the European Commission's Strategic Energy Technology Plan lists target LCOE figures for the latest generation of light-water reactors (LWRs) 'first-of-a-kind' new-build twin reactor project on a brownfield site as €48/MWh to €84/MWh, falling to €43/MWh to €75/MWh for a series build (5% and 10% discount rate, in 2012€). The LCOE figures for existing Generation II nuclear power plants integrating post-Fukushima stress tests safety upgrades following refurbishment for extended operation (10-20 years on average) are €23/MWh to €26/MWh (5% and 10% discount rate, in 2012€).

The 2010 edition of the OECD study on Projected Costs of generating Electricity compared 2009 data for generating base-load electricity by 2015 as well as costs of power from renewables, and showed that nuclear power was very competitive at $30 per tonne CO2 cost and low discount rate. The study comprised data for 190 power plants from 17 OECD countries as well as some data from Brazil, China, Russia and South Africa. It used levelised lifetime costs with carbon price internalised (OECD only) and discounted cash flow at 5% and 10%, as previously. The precise competitiveness of different base-load technologies depended very much on local circumstances and the costs of financing and fuels.

Nuclear overnight capital costs in OECD ranged from US$ 1556/kW for APR-1400 in South Korea through $3009 for ABWR in Japan, $3382/kW for Gen III+ in USA, $3860 for EPR at Flamanville in France to $5863/kW for EPR in Switzerland, with world median $4100/kW. Belgium, Netherlands, Czech Rep and Hungary were all over $5000/kW. In China overnight costs were $1748/kW for CPR-1000 and $2302/kW for AP1000, and in Russia $2933/kW for VVER-1150. EPRI (USA) gave $2970/kW for APWR or ABWR, Eurelectric gave $4724/kW for EPR. OECD black coal plants were costed at $807-2719/kW, those with carbon capture and compression (tabulated as CCS, but the cost not including storage) at $3223-5811/kW, brown coal $1802-3485, gas plants $635-1747/kW and onshore wind capacity $1821-3716/kW. (Overnight costs were defined here as EPC, owner's costs and contingency, but excluding interest during construction.)

OECD electricity generating cost projections for year 2010 on – 5% discount rate, c/kWh

country nuclear coal coal with CCS Gas CCGT Onshore wind
Belgium 6.1 8.2 - 9.0 9.6
Czech R 7.0 8.5-9.4 8.8-9.3 9.2 14.6
France 5.6 - - - 9.0
Germany 5.0 7.0-7.9 6.8-8.5 8.5 10.6
Hungary 8.2 - - - -
Japan 5.0 8.8 - 10.5 -
Korea 2.9-3.3 6.6-6.8 - 9.1 -
Netherlands 6.3 8.2 - 7.8 8.6
Slovakia 6.3 12.0 - - -
Switzerland 5.5-7.8 - - 9.4 16.3
USA 4.9 7.2-7.5 6.8 7.7 4.8
China* 3.0-3.6 5.5 - 4.9 5.1-8.9
Russia* 4.3 7.5 8.7 7.1 6.3
EPRI (USA) 4.8 7.2 - 7.9 6.2
Eurelectric 6.0 6.3-7.4 7.5 8.6 11.3

* For China and Russia: 2.5c is added to coal and 1.3c to gas as carbon emission cost to enable sensible comparison with other data in those fuel/technology categories, though within those countries coal and gas will in fact be cheaper than the Table above suggests.
Source: OECD/IEA NEA 2010, table 4.1.

At 5% discount rate comparative costs are as shown above. Nuclear is comfortably cheaper than coal and gas in all countries. At 10% discount rate (below) nuclear is still cheaper than coal in all but the Eurelectric estimate and three EU countries, but in these three gas becomes cheaper still. Coal with carbon capture is mostly more expensive than either nuclear or paying the $30 per tonne for CO2 emissions, though the report points out "great uncertainties" in the cost of projected CCS. Also, investment cost becomes a much greater proportion of power cost than with 5% discount rate.

OECD electricity generating cost projections for year 2010 on – 10% discount rate, c/kWh

country nuclear coal coal with CCS Gas CCGT Onshore wind
Belgium 10.9 10.0 - 9.3-9.9 13.6
Czech R 11.5 11.4-13.3 13.6-14.1 10.4 21.9
France 9.2 - - - 12.2
Germany 8.3 8.7-9.4 9.5-11.0 9.3 14.3
Hungary 12.2 - - - -
Japan 7.6 10.7 - 12.0 -
Korea 4.2-4.8 7.1-7.4 - 9.5 -
Netherlands 10.5 10.0 - 8.2 12.2
Slovakia 9.8 14.2 - - -
Switzerland 9.0-13.6 - - 10.5 23.4
USA 7.7 8.8-9.3 9.4 8.3 7.0
China* 4.4-5.5 5.8 - 5.2 7.2-12.6
Russia* 6.8 9.0 11.8 7.8 9.0
EPRI (USA) 7.3 8.8 - 8.3 9.1
Eurelectric 10.6 8.0-9.0 10.2 9.4 15.5

* For China and Russia: 2.5c is added to coal and 1.3c to gas as carbon emission cost to enable sensible comparison with other data in those fuel/technology categories, though within those countries coal and gas will in fact be cheaper than the Table above suggests.
Source: OECD/IEA NEA 2010, table 4.1.

A 2004 report on The Economic Future of Nuclear Power from from the University of Chicago, funded by the US Department of Energy, compared the levelised power costs of future nuclear, coal, and gas-fired power generation in the USA. Various nuclear options were covered, and for an initial ABWR or AP1000 they ranged from 4.3 to 5.0 c/kWh on the basis of overnight capital costs of $1200 to $1500/kW, 60-year plant life, five-year construction and 90% capacity. Coal gave 3.5-4.1 c/kWh and gas (CCGT) 3.5-4.5 c/kWh, depending greatly on fuel price.

The levelised nuclear power cost figures included up to 29% of the overnight capital cost as interest, and the report noted that up to another 24% of the overnight capital cost needs to be added for the initial unit of a first-of-a-kind advanced design such as the AP1000, defining the high end of the range above. For plants such as the EPR or SWR1000, overnight capital cost of $1800/kW was assumed and power costs were projected beyond the range above. However, considering a series of eight units of the same kind and assuming increased efficiency due to experience which lowers overnight capital cost, the levelised power costs dropped 20% from those quoted above and where first-of-a-kind engineering costs are amortised (e.g. the $1500/kW case above), they dropped 32%, making them competitive at about 3.4 c/kWh.

Nuclear plant: projected electrcity costs (c/kWh)

Overnight capital cost $/kW 1200 1500 1800
First unit 7 yr build, 40 yr life
5.3
6.2
7.1
  5 yr build, 60 yr life
4.3
5.0
5.8
4th unit 7 yr build, 40 yr life
4.5
4.5
5.3
  5 yr build, 60 yr life *
3.7
3.7
4.3
8th unit 7 yr build, 40 yr life
4.2
4.2
4.9
  5 yr build, 60 yr life *
3.4
3.4
4.0

* calculated from above data

The study also showed that with a minimal carbon control cost impact of 1.5 c/kWh for coal and 1.0 c/kWh for gas superimposed on the above figures, nuclear is even more competitive. But more importantly it went on to explore other policy options which would offset investment risks and compensate for first-of-a-kind engineering costs to encourage new nuclear investment, including investment tax breaks, and production tax credits phasing out after 8 years. (US wind energy gets a production tax credit which has risen to 2.1 c/kWh.)

In May 2009 an update of a heavily-referenced 2003 MIT study on The Future of Nuclear Power was published. This said that "since 2003 construction costs for all types of large-scale engineered projects have escalated dramatically. The estimated cost of constructing a nuclear power plant has increased at a rate of 15% per year heading into the current economic downturn. This is based both on the cost of actual builds in Japan and Korea and on the projected cost of new plants planned for in the United States. Capital costs for both coal and natural gas have increased as well, although not by as much. The cost of natural gas and coal that peaked sharply is now receding. Taken together, these escalating costs leave the situation [of relative costs] close to where it was in 2003." The overnight capital cost was given as $4000/kW, in 2007 dollars. Applying the same cost of capital to nuclear as to coal and gas, nuclear came out at 6.6 c/kWh, coal at 8.3 cents and gas at 7.4 cents, assuming a charge of $25/tonne CO2 on the latter.

The French Energy & Climate Directorate published in November 2008 an update of its earlier regular studies on relative electricity generating costs. This shied away from cash figures to a large extent due to rapid changes in both fuel and capital, but showed that at anything over 6000 hours production per year (68% capacity factor), nuclear was cheaper than coal or gas combined cycle (CCG). At 100% capacity CCG was 25% more expensive than nuclear. At less than 4700 hours per year CCG was cheapest, all without taking CO2 cost into account.

With the nuclear plant fixed costs were almost 75% of the total, with CCG they were less than 25% including allowance for CO2 at $20/t. Other assumptions were 8% discount rate, gas at 6.85 $/GJ, coal at EUR 60/t. The reference nuclear unit is the EPR of 1630 MWe net, sited on the coast, assuming all development costs being borne by Flamanville 3, coming on line in 2020 and operating only 40 of its planned 60 years. Capital cost apparently EUR 2000/kW. Capacity factor 91%, fuel enrichment is 5%, burnup 60 GWd/t and used fuel is reprocessed with MOX recycle. In looking at overall fuel cost, uranium at $52/lb made up about 45% of it, and even though 3% discount rate was used for back-end the study confirmed the very low cost of waste in the total - about 13% of fuel cost, mostly for reprocessing.

A detailed study of energy economics in Finland published in mid 2000 was important in making the strong case for additional nuclear construction there, showing that nuclear energy would be the least-cost option for new generating capacity. The study compared nuclear, coal, gas turbine combined cycle and peat. Nuclear had very much higher capital costs than the others – €1749/kW including initial fuel load, which was about three times the cost of the gas plant. But its fuel costs were much lower, and so at capacity factors above 64% it was the cheapest option.

August 2003 figures from Finland put nuclear costs at €2.37 c/kWh, coal 2.81 c/kWh and natural gas at 3.23 c/kWh (on the basis of 91% capacity factor, 5% interest rate, 40-year plant life). With emission trading @ €20/t CO2, the electricity prices for coal and gas increased to 4.43 and 3.92 c/kWh respectively:
 

Projected Electricity Costs for Finland 2003 - cent/kWh stacked column graph


In the middle three bars of this graph the relative effects of capital and fuel costs can be clearly seen. The relatively high capital cost of nuclear power means that financing cost and time taken in construction are critical, relative to gas and even coal. But the fuel cost is very much lower, and so once a plant is built its cost of production is very much more predictable than for gas or even coal. The impact of adding a cost or carbon emissions can also be seen.

In 2013 the Nuclear Energy Institute announced the results of its financial modelling of comparative costs in the USA, based on figures from the US Energy Information Administration’s 2013 Annual Energy Outlook. NEI assumed 5% cost of debt, 15% return on equity and a 70/30 debt equity capital structure. The figures are tabulated below. The report went on to show that with nuclear plant licence renewal beyond 60 years, power costs would be $53-60/MWh.

NEI 2013 Financial Modelling

  EPC cost capacity Electricity cost
Gas combined cycle, gas @ $3.70/GJ $1000/kW 90% $44.00/MWh
Gas combined cycle, gas @ $5.28/GJ $1000/kW 90% $54.70/MWh
Gas combined cycle, gas @ $6.70/GJ $1000/kW 90% $61.70/MWh
Gas combined cycle, gas @ $6.70/GJ, 50-50 debt-equity $1000/kW 90% c $70/MWh
Supercritical pulverised coal, 1300 MWe $3000/kW 85% $75.70/MWh
Integrated gasification combined cycle coal, 1200 MWe $3800/kW 85% $94.30/MWh
Nuclear, 1400 MWe (EIA's EPC figure) $5500/kW 90% $121.90/MWh
Nuclear, 1400 MWe (NEI suggested EPC figure) $4500-5000/kW 90% $85-90/MWh
Wind farm, 100 MWe $1000/kW 30% 112.90/MWh

5% cost of debt, 15% return on equity and a 70-30 debt equity capital structure.

In mid-2015 the NEI published figures from the Institute for Energy Research (IER) report The Levelized Cost of Electricity from Existing Generation Resources, including the finding that nuclear energy had the lowest average costs of electricity for operating facilities. For new plants, it showed nuclear at just over $90/MWh, compared with coal almost $100/MWh and gas just over $70/MWh.

The China Nuclear Energy Association estimated in May 2013 that the construction cost for two AP1000 units at Sanmen are CNY 40.1 billion ($6.54 billion), or 16,000 Yuan/kW installed ($2615/kW) – about 20% higher than that of improved Generation II Chinese reactors, but likely to drop to about CNY 13,000/kW ($2120/kW) with series construction and localisation as envisaged. Grid purchase price is expected to exceed CNY 0.45/kWh at present costs, and drop to 0.42 with reduced capital cost.

A striking indication of the impact of financing costs is given by Georgia Power, which said in mid 2008 that twin 1100 MWe AP1000 reactors would cost $9.6 billion if they could be financed progressively by ratepayers, or $14 billion if not. This gives $4363 or $6360 per kilowatt including all other owners costs.

Finally, in the USA the question of whether a project is subject to regulated cost recovery or is a merchant plant is relevant, since it introduces political, financial and tactical factors. If the new build cost escalates (or is inflated), some cost recovery may be possible through higher rates can be charged by the utility if those costs are deemed prudent by the relevant regulator. By way of contrast, a merchant plant has to sell all its power competitively, so must convince its shareholders that it has a good economic case for moving forward with a new nuclear unit.

Financing new nuclear power plants

There is a range of possibilities for financing, from direct government funding with ongoing ownership, vendor financing (often with government assistance), utility financing and the Finnish Mankala model for cooperative equity. Some of the cost is usually debt financed. The models used will depend on whether the electricity market is regulated or liberalised.

Apart from centrally-planned economies, many projects have some combination of government financial incentives, private equity and long-term power purchase arrangements. The increasing involvement of reactor vendors is a recent development.

Some options are described in the WNA 2012 report on Nuclear Power Economics and Project Structuring.

Providing investment incentives

As more electricity markets become deregulated and competitive, balancing supply and demand over the short-term can result in significant price volatility. Price signals in the spot market for electricity supply do not provide a guide on the return that might be achieved over the long term, and fail to create incentive for long-term investment in generation or transmission infrastructure, nor do they value diversity of supply.

World Nuclear News editorial in February 2015 addressed this issue helpfully.

Deregulated electricity markets with preferential grid access for renewables have left some utilities with stranded assets, which can no longer be used sufficiently fully to be profitable. As a result, many are being decommissioned, eg about 9 GWe by E.On and RWE in Germany to 2013, and a further 7.3 GWe expected there (apart from nuclear capacity).

The economic rationale for electricity from any plants with high capital cost and long life does not translate into incentive for investment unless some long-term electricity price is assured. This has been tackled differently in various countries.

In the USA, investment in new capital-intensive plant is going ahead only in states where cost-recovery can be assured, not in deregulated areas. Proposed merchant plants in Texas and some eastern states have been postponed indefinitely.

In Ontario, Canada, the refurbishment of Bruce A 1&2 was underwritten by a power purchase agreement (PPA) at about $63/MWh, slightly higher than the regulated price. The refurbishment of Bruce A 3&4 (1500 MWe) from 2016 and the C$ 8 billion needed for the Bruce B units (3480 MWe) from 2020 is likely to be underwritten similarly with PPAs.

In the UK, legislation from 2013 has three main elements:

  • Feed-in tariffs (FIT), now relatively common in several countries, give particular low-carbon producers a predictable return per kWh over a set period regardless of prevailing market prices. The FIT can take several forms. In the UK it will be effected through contracts for difference (CfD) which remove long-term exposure to electricity price volatility. The FIT with CfD means that if the market price is lower that the agreed ‘strike price’, the government or the transmission system operator (TSO) pays that difference per kWh, if the market is above the strike price the generator pays the TSO or government. They are long-term contracts which can be capped regarding quantity of power, helping developers secure the large upfront capital costs for low-carbon infrastructure while protecting consumers from rising energy bills. The first strike prices were published in the 2013-18 Delivery Plan: £155/MWh for offshore wind, £100/MWh for onshore wind and £125/MWh for large solar PV.
  • A floor price for ‘carbon’ to support de-carbonisation. The idea is that a carbon floor price will drive the market towards any FIT or strike price level applied to clean sources.
  • Capacity market measures will be introduced. These involve payments for dispatchable capacity maintained to ensure that demand can be met regardless of short-term conditions affecting other generators. They will work through penalties and availability payments to provide incentive for generators to be available when needed, in effect paying for reliability. The first capacity auction is scheduled for late 2014, for delivery during winter 2018-19.

In October 2013 the UK government announced that initial agreement had been reached with EDF Group on the key terms of a proposed £16 billion investment contract for the Hinkley Point C nuclear power station. The key terms include 35-year ‘Contract for Difference’, the Strike Price of £89.50/MWh being fully indexed to the Consumer Price Index and conditional upon the Sizewell C project proceeding. If it does not for any reason, and the developer cannot share first-of-a-kind costs across both, the strike price is to be £92.50/MWh. EDF said that the agreement in principle is not legally binding, and is dependent on a positive decision from the European Commission in relation to State Aid, following which it will make a final decision on the project. As well as price per MWh, the question of guaranteed load factor arises so that output is sufficient to amortise the investment, in the face of renewables’ preferential grid access.

In the Czech Republic, CEZ says that investment in two new 1200 MWe reactors at Temelin will not proceed unless it has some assurance of long-term electricity prices from them. The government and Ministry of Finance are resisting this. The Industry Ministry was proposing €60/MWh, others suggest that €90 will be needed, indexed. CEZ requires €70/MWh for the new units to be profitable, compared with mid-2013 forward prices of under €40.

 

In Turkey, in order to secure investment in the 4x1200 MWe Akkuyu nuclear power plant, a formula for long-term power prices was worked out. This involves the Turkish Electricity Trade & Contract Corporation (TETAS) buying a fixed proportion of the power at a fixed price of US$ 123.50/MWh for 15 years, or to 2030. The proportion will be 70% of the output of the first two units and 30% of that from units 3&4 over 15 years from commercial operation of each. Rosatom will initially have full ownership of the project.

The first power station to produce electricity by using heat from the splitting of uranium atoms began operating in the 1950s. Today most people are aware of the important contribution nuclear energy makes in cleanly providing a significant proportion of the world's electricity.

Not so well known are the many other ways the peaceful atom has slipped quietly into our lives, often unannounced and in many cases unappreciated.

Radioisotopes and radiation have many applications in agriculture, medicine, industry and research. They greatly improve the day to day quality of our lives.

What is a radioisotope?

Isotopes are different forms of an atom of the same chemical element. They have identical chemical properties but different relative atomic masses. While the number of protons is the same, the number of neutrons in the nucleus differs. 

Some isotopes are referred to as 'stable' and unchanging, while others are 'unstable' since their nucleus changes over time – from milliseconds to millennia – as they emit charged particles or waves, making them 'radioactive'. It is the radioactive nature of these unstable atoms, usually referred to as 'radioisotopes', which gives them so many applications in modern science and technology. Their radioactivity means that they can be used as a tag to follow the movement of some material incorporating them.

George de Hevesy

The first practical application of a radioisotope was made by George de Hevesy in 1911. At the time de Hevesy was a young Hungarian student working in Manchester with naturally radioactive materials. Not having much money he lived in modest accommodation and took his meals with his landlady. He began to suspect that some of the meals that appeared regularly might be made from leftovers from the preceding days or even weeks, but he could never be sure. To try and confirm his suspicions de Hevesy put a small amount of radioactive material into the remains of a meal. Several days later when the same dish was served again he used a simple radiation detection instrument - a gold leaf electroscope - to check if the food was radioactive. It was, and de Hevesy's suspicions were confirmed.

History has forgotten the landlady, but George de Hevesy went on to win the Nobel prize in 1943 and the Atoms for Peace award in 1959. His was the first use of radioactive tracers - now routine in environmental science.

Scientists continue to find new and beneficial ways of using nuclear technology to improve our lives. In our daily life we need food, water and good health. Radioisotopes play an important part in technologies that provide us with these basic needs. The UN's International Atomic Energy Agency (IAEA) is a base for international cooperation in hundreds of development projects.

Food and Agriculture 

At least 800 million of the world's seven billion inhabitants are chronically malnourished, and tens of thousands die daily from hunger and hunger-related causes. Radioisotopes and radiation used in food and agriculture are helping to reduce these tragic figures.

As well as directly improving food production, agriculture needs to be sustainable over the longer term. The UN's Food and Agriculture Organisation (FAO) works with the IAEA on programs to improve food sustainability assisted by nuclear and related biotechnologies.

Fertilisers

Fertilisers are expensive and if not properly used can damage the environment. Efficient use of fertilisers is therefore of concern to both developing and developed countries. It is important that as much of the fertiliser as possible finds its way into plants and that a minimum is lost to the environment.

Fertilisers 'labelled' with a particular isotope, such as nitrogen-15 and phosphorus-32 provide a means of finding out how much is taken up by the plant and how much is lost, allowing better management of fertiliser application. Using N-15 also enables assessment of how much nitrogen is fixed from the air by soil and by root bacteria in legumes.

Increasing Genetic Variability

Ionising radiation to induce mutations in plant breeding has been used for several decades, and some 1800 crop varieties have been developed in this way. Gamma or neutron irradiation is often used in conjunction with other techniques, to produce new genetic lines of root and tuber crops, cereals and oil seed crops.

New kinds of sorghum, garlic, wheat, bananas, beans and peppers are more resistant to pests and more adaptable to harsh climatic conditions. In Mali, irradiation of sorghum and rice seeds has produced more productive and marketable varieties.

Insect Control 

Crop losses caused by insects may amount to more than 10% of the total harvest worldwide, - in developing countries the estimate is 25-35%. Stock losses due to tsetse in Africa and screwworm in Mexico have also been sizeable. Chemical insecticides have for many years been the main weapon in trying to reduce these losses, but they have not always been effective. Some insects have become resistant to the chemicals used, and some insecticides leave poisonous residues on the crops. One solution has been the use of sterile insects.

The Sterile Insect Technique (SIT) involves rearing large numbers of insects then irradiating their eggs with gamma radiation before hatching, to sterilise them. The sterile males are then released in large numbers in the infested areas. When they mate with females, no offspring are produced. With repeated releases of sterilised males, the population of the insect pest in the project area is drastically reduced.

Major SIT operations have been conducted in Mexico, Argentina and northern Chile against the Medfly (Mediterranean fruit fly) and in 1981 this was declared a complete success in Mexico. In 1994-95 eradication was achieved in two fruit-growing areas of Argentina and 95% success in another, as well as in Chile. The program has been extended to all of southern South America and to Africa. Meanwhile the EU is financing a 'fly factory' on Portugal's Madeira island to produce up to 100 million sterile male Medflies per week.

A very successful SIT campaign was screwworm eradication in southern USA, Mexico and nearby. By 1991 the screwworm eradication had yielded some US$ 3 billion in economic benefits due to healthier livestock, not to mention humans. The Mexican plants and equipment were then applied to infestations in Libya, Jamaica and Central America, providing 20 million sterile pupae per week.

SIT has been effective on the Medfly in southern Africa and is now being applied to Codling Moths which damage citrus crops. The IAEA and FAO are assessing the potential of using SIT against Sugarcane Borers on sugarcane, as well as consolidating Codling Moth management to support the apple and pear export industries. 

A number of the most fertile parts of Africa cannot be farmed because of the tsetse fly which carries the parasite trypanosome that causes the African sleeping sickness disease and the cattle disease Nagana. Economic losses due to this are estimated by FAO at US$ 4 billion per year. However, SIT in conjunction with conventional pest controls is starting to change all this. Zanzibar was declared tsetse-free in 1997 and Nigeria has also benefited. In southern Ethiopia a major tsetse SIT program is under way, with a million sterile males per month being produced in a 'fly factory' at Addis Ababa and then released.

Screwworm flies are major pests in some parts of the world. Females lay eggs into animal wounds and on soft tissues, the larvae then burrow through the flesh creating serious bacterial infections that attract more egg-laying females and are often fatal. Using SIT, screwworm has been eradicated from North and Central America, and also Libya. South America, most of Africa, and south Asia through to Melanesia remain a challenge. 

Three UN organizations - the IAEA, the FAO, the World Health Organisation (WHO), with the governments concerned, are promoting new SIT programs in many countries. 

Food Preservation 

Some 25-30% of the food harvested in many countries is lost as a result of spoilage by microbes and pests. In a hungry world we cannot afford this. The reduction of spoilage due to infestation and contamination is of the utmost importance. This is especially so in countries which have hot and humid climates and where an extension of the storage life of certain foods, even by a few days, is often enough to save them from spoiling before they can be consumed. Some countries lose a high proportion of harvested grain due to moulds and insects.

In all parts of the world there is growing use of irradiation technology to preserve food. In over 40 countries health and safety authorities have approved irradiation of more than 60 kinds of food, ranging from spices, grains and grain products to fruit, vegetables and meat. It can replace potentially harmful chemical fumigants to eliminate insects from dried fruit and grain, legumes, and spices. 

Following three decades of testing, a worldwide standard was adopted in 1983 by a joint committee of WHO, FAO and IAEA. In 1997 another such joint committee said there was no need for the earlier recommended upper limit on radiation dose to foods.

As well as reducing spoilage after harvesting, increased use of food irradiation is driven by concerns about food-borne diseases as well as growing international trade in foodstuffs which must meet stringent standards of quality. On their trips into space, astronauts eat foods preserved by irradiation.

Food irradiation means that raw foods are exposed to high levels of gamma radiation which kills bacteria and other harmful organisms without affecting the nutritional value of food itself or leaving any residue. It is the only means of killing bacterial pathogens in raw and frozen food. Of course, irradiation of food does not make it radioactive!

Food irradiation applications  

Low dose (up to 1 kGy)  Inhibition of sprouting Potatoes, onions, garlic, ginger, yam
  Insect and parasite disinfestation Cereals, fresh fruit, dried foods
  Delay ripening Fresh fruit, vegetables
Medium dose (1-10 kGy)  Extend shelf life Fish, strawberries, mushrooms
  Halt spoilage, kill pathogens Seafood, poultry, meat
High dose (10-50 Gy)  Industrial sterilisation Meat, poultry, seafood, prepared foods
  Decontamination Spices, etc

Radiation is also used to sterilise food packaging. In the Netherlands, for example, milk cartons are freed from bacteria by irradiation.

Water Resources 

Adequate potable water is essential for life. Yet in many parts of the world fresh water has always been scarce and in others it is becoming scarcer. Yet for any new development, whether agricultural, industrial or human settlement, a sustainable supply of good water is vital.

Isotope hydrology techniques enable accurate tracing and measurement of the extent of underground water resources. Such techniques provide important analytical tools in the management and conservation of existing supplies of water and in the identification of new, renewable sources of water. They provide answers to questions about origin, age and distribution of groundwater, as well as the interconnections between ground and surface water and aquifer recharge systems. The results permit planning and sustainable management of these water resources. 

For surface waters they can give information about leakages through dams and irrigation channels, the dynamics of lakes and reservoirs, flow rates, river discharges and sedimentation rates. From Afghanistan to Zaire there are some 60 countries, developed and developing, that have used isotope techniques to investigate their water resources in collaboration with IAEA.

Neutron probes can measure soil moisture very accurately, enabling better management of land affected by salinity, particularly in respect to irrigation.

Medicine 

Many of us are aware of the wide use of radiation and radioisotopes in medicine particularly for diagnosis (identification) andtherapy (treatment) of various medical conditions. In developed countries (a quarter of the world population) about one person in fifty uses diagnostic nuclear medicine each year, and the frequency of therapy with radioisotopes is about one tenth of this.

Over 10,000 hospitals worldwide use radioisotopes in medicine. In the USA there are over 20 million nuclear medicine procedures per year among 315 million people, and in Europe about 10 million among 500 million people. The use of radiopharmaceuticals in diagnosis is growing at over 10% per year.

Diagnosis 

Radioisotopes are an essential part of medical diagnostic procedures. In combination with imaging devices which register the gamma rays emitted from within, they can study the dynamic processes taking place in various parts of the body. An advantage of nuclear over x-ray techniques is that both bone and soft tissue can be imaged very successfully.

In using radiopharmaceuticals for diagnosis, a radioactive dose is given to the patient and the activity in the organ can then be studied either as a two dimensional picture or, with a special technique called tomography, as a three dimensional picture. 

The most widely used diagnostic radioisotope is technetium-99m*, with a half-life of six hours, and which gives the patient a very low radiation dose. Such isotopes are ideal for tracing many bodily processes with the minimum of discomfort for the patient. They are widely used to indicate tumours and to study the heart, lungs, liver, kidneys, blood circulation and volume, and bone structure.

* Technetium generators, a lead pot enclosing a glass tube containing the radioisotope, are supplied to hospitals from the nuclear reactor where the isotopes are made. They contain molybdenum-99, with a half-life of 66 hours, which progressively decays to technetium-99. The Tc-99 is washed out of the lead pot by saline solution when it is required. After two weeks or less the generator is returned for recharging.

Technetium (Tc-99) is employed in some 40 million diagnostic procedures per year, of which almost one quarter are in Europe, half in North America, almost one quarter in Asia/Pacific (particularly Japan), and a few in other regions. The chemistry of technetium is so versatile it can form tracers by being incorporated into a range of biologically-active substances to ensure that it concentrates in the tissue or organ of interest.

Another major use of radioisotopes for diagnosis is in radio-immuno-assays for biochemical analysis in a laboratory. They can be used to measure very low concentrations of hormones, enzymes, hepatitis virus, some drugs and a range of other substances in a sample of the patient's blood. The patient never comes in contact with the radioisotopes used in the diagnostic tests. In the USA alone it is estimated that some 40 million such tests are carried out each year, and in Europe, about 15 million. 

Therapy

The uses of radioisotopes in therapy are comparatively few, but important. Cancerous growths are sensitive to damage by radiation, which may be external - using a gamma beam from a cobalt-60 source, or internal - using a small gamma or beta radiation source. Short-range radiotherapy is known as brachytherapy, and this is becoming the main means of treatment. Many therapeutic procedures are palliative, usually to relieve pain.

Iodine-131 is commonly used to treat thyroid cancer, probably the most successful kind of cancer treatment, and also for non-malignant thyroid disorders. Iridium-192 wire implants are used especially in the head and breast to give precise doses of beta rays to limited areas, then removed. A new treatment uses samarium-153 complexed with organic phosphate to relieve the pain of secondary cancers lodged in bone.

A new field is Targeted Alpha Therapy (TAT), especially for the control of dispersed cancers. The short range of very energetic alpha emissions in tissue means that a large fraction of that radiative energy goes into the targeted cancer cells, once a carrier such as a monoclonal antibody has taken the alpha-emitting radionuclide to exactly the right places.

(See also information paper Radioisotopes in Medicine)

Sterilisation  

Many medical products today are sterilised by gamma rays from a cobalt-60 source, a technique which generally is much cheaper and more effective than steam heat sterilisation. The disposable syringe is an example of a product sterilised by gamma rays. Because it is a 'cold' process radiation can be used to sterilise a range of heat-sensitive items such as powders, ointments and solutions and biological preparations such as bone, nerve, skin, etc, used in tissue grafts.  

The benefit to humanity of sterilisation by radiation is tremendous. It is safer and cheaper because it can be done after the item is packaged. The sterile shelf life of the item is then practically indefinite provided the package is not broken open. Apart from syringes, medical products sterilised by radiation include cotton wool, burn dressings, surgical gloves, heart valves, bandages, plastic and rubber sheets and surgical instruments.

Smoke detectors

One of the commonest uses of radioisotopes today is in household smoke detectors. These contain a small amount of americium-241 which is a decay product of plutonium-241 originating in nuclear reactors. The Am-241 emits alpha particles which ionise the air and allow a current between two electrodes. If smoke enters the detector it absorbs the alpha particles and interrupts the current, setting off the alarm. 

(See also information paper Smoke Detectors and Americium)

Industry 

Environmental tracers

Radioisotopes also play an important role in detecting and analysing pollutants, since even very small amounts of a radioisotope can easily be detected, and the decay of short-lived isotopes means that no residues remain in the environment. 

Nuclear techniques have been applied to a range of pollution problems including smog formation, sulphur dioxide contamination of the atmosphere, sewage dispersal from ocean outfalls and oil spills. 

Industrial tracers

The ability to measure radioactivity in minute amounts has given radioisotopes a wide range of applications in industry as 'tracers'. By adding small amounts of radioactive substances to materials used in various processes it is possible to study the mixing and flow rates of a wide range of materials, including liquids, powders and gases and to locate leaks.

Tracers added to lubricating oils can help measure the rate of wear of engines and plant and equipment. Tracer techniques have been used in plant operations to check the performance of equipment and improve its efficiency, resulting in savings in energy and the better use of raw materials.

Instruments

Gauges containing radioactive (usually gamma) sources are in wide use in all industries where levels of gases, liquids and solids must be checked. They measure the amount of radiation from a source which has been absorbed in materials. These gauges are most useful where heat, pressure or corrosive substances, such as molten glass or molten metal, make it impossible or difficult to use direct contact gauges. 

  Radioisotope thickness gauges are used in the making of continuous sheets of material including paper, plastic film, metal, glass, etc, when it is desirable to avoid contact between the gauge and the material. 

Density gauges are used where automatic control of a liquid, powder or solid is important, for example, in detergent manufacture. 

Radioisotope instruments have three great advantages:

  • measurements can be made without physical contact with the material or product being measured.
  • Very little maintenance of the isotope source is necessary.
  • The cost/benefit ratio is excellent - many instruments pay for themselves within a few months through the savings they allow.

Radiography

Radioisotopes which emit gamma rays are more portable than x-ray machines, and may give higher-energy radiation, so can be used to check welds of new gas and oil pipeline systems, with the radioactive source being placed inside the pipe and the film outside the welds. 

Other forms of radiography (neutron radiography/ autoradiography), based on different principles, can be used to gauge the thickness and density of materials or locate components that are not visible by other means.

(See also information paper Radioisotopes in Industry)

Radioisotope power sources

Some radioisotopes emit a lot of energy as they decay. Such energy can be harnessed for heart pacemakers and to power navigation beacons and satellites. The decay heat of plutonium-238 has powered many US space vehicles. It enabled the Cassini space probe to investigate Saturn, and it powers the Mars Science Laboratory, the rover Curiosity

Dating

Analysing the relative abundance of particular naturally-occurring radioisotopes is of vital importance in determining the age of rocks and other materials that are of interest to geologists, anthropologists and archaeologists. 

Conclusion

 

From the moment we get up in the morning, until we go to sleep, we benefit unknowingly from many ingenious applications of radioisotopes and radiation. The water we wash with (origin, supply assurance), the textiles we wear (manufacture control gauging), the breakfast we eat (improved grains, water analysis), our transport to work (thickness gauges for checking steels and coatings on vehicles and assessing the effects of corrosion and wear on motor engines), the bridges we cross (neutron radiography), the paper we use (gauging, mixing during production processes), the drugs we take (analysis) not to mention medical tests (radioimmunoassay, perhaps radiopharmaceuticals), or the environment which radioisotope techniques help to keep clean, are all examples that we sometimes take for granted.