The Economics of Nuclear Power: An Update

Cost estimates for new nuclear plants have been escalating at
an alarming rate, and in the past decade, construction costestimates have increased five-fold, with every expectation thatcosts will increase further as the designs are firmed up. In addition, there are the unsolved problems of waste disposal andthe high susceptibility of the technology to failure. Up to now,
nuclear power plants have been funded by massive public subsidies. For Germany the calculations roughly add up to over
100 billion Euros and this preferential treatment is still goingon today. As a result the billions set aside for the disposal of
nuclear waste and the dismantling of nuclear power plants represent a tax-free manoeuvre for the companies. In addition theliability of the operators is limited to 2.5 billion Euros – a tiny
proportion of the costs that would result from a medium-sized

Rue d’Arlon 15, -1050 Brussels, Belgium
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nuclear accident. Yet, in recent years, governments have become
increasingly determined in their attempts to maintain existing
nuclear plants in service and revive nuclear ordering, on the
grounds that nuclear power is the most cost-effective way tocombat climate change. Some of this apparent paradox is relatively easily explained by the difference between the runningcosts only of nuclear power, which are usually relatively low,
and the overall cost of nuclear power – including repaymentof the construction cost – which is substantially higher. The
objective of this report is to identify the key economic parameters that determine the cost of nuclear electricity, commenting
on their determining factors. It shows that without subsidies
and guarantees from electricity consumers and taxpayers, newnuclear power plants will not be built.

The Economics of Nuclear
Power: An Update
By Steve Thomas

publication series on ecology

The Economics of Nuclear Power:
An Update
By Steve Thomas, March 2010
Edited by the Heinrich Böll Foundation

With the support of theHeinrich-Böll-Stiftung
Published by the Heinrich-Böll-Stiftung, European Union, Brussels
Printed in Belgium, September 2010
© The authors, the Heinrich-Böll-Stiftung, European Union, Brussels
All rights reserved
English proof-reading and language editing: Katarzyna Radzikowska
Coordination and final editing: Annett Waltersdorf
Print production: Micheline Gutman
Cover picture: iStockphoto.com © Björn Kindler
Pictures of Chapters 1, 3 and 8: One-time, non-exclusive, editorial use only. No archive, redistribution orreuse in another context without prior permission from Greenpeace Photo Library. Not for advertising or
promotional use. Credit compulsory.
Some rights reserved for the pictures of Chapters 4, 5, 6 and 7. They are attached to the following Creative
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D/2010/11.850/5
This publication can be ordered at:
Heinrich-Böll-Stiftung, European Union, Brussels
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B-1050 Brussels
Belgium
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TABLE OF CONTENTS
Preface: Nuclear Energy – a Dead End 

5

Author’s note
Introduction
1.	The world market for nuclear plants: existing orders and prospects

7

2. Key determinants of nuclear economics 
2.1. Construction cost and time		
2.1.1. Unreliability of data		
2.1.2. Difficulties of forecasting		
2.1.3. Learning, scale economies, and technical progress		
2.1.4. Construction time2.2. Cost of capital
2.3. Operating performance
2.4. Non-fuel operations and maintenance costs
2.5. Fuel cost
2.6. Accounting lifetime
2.7. Decommissioning and waste disposal cost and provisions
2.8. Insurance and liability
3.	Experience at Olkiluoto and Flamanville
3.1. Olkiluoto3.2. Flamanville



8
9
16
17
17
18
19
20
21
22
24
25
26
26
27
29
29
30

4.	The us programme
4.1. Likely outcomes

32
36

5.	The uk programme
5.1. Likely outcomes

38
39

6.	Germany

41

7.	Other markets
7.1. United Arab Emirates
7.2. South Africa
7.3. Canada
7.4. Turkey
7.5. Italy
7.6. Brazil
7.7. Eastern Europe		
7.7.1. Slovak Republic		
7.7.2. Romania		
7.7.3. Bulgaria
		
7.7.4. Other countries

42
42
43
44
44
45
45
45
46
46
46
46

8.	Review of utility construction cost-estimates
8.1. United States
8.2. Other countries
8.3. Summary

48
48
49
49

9. Need for and extent of public subsidies51

Conclusions

53

Appendices
Appendix 1
Appendix 2
Appendix 3
Appendix 4

Reactor technologies, current designs, and vendors
Discounting, cost of capital, and required rate of return
Decommissioning
Status of US projects



55
55
61
62
65

Preface 

5

Preface: Nuclear Energy – a Dead End

Anyone following the statements expressedfrom time to time about the renaissance of nuclear energy could get the impression that the
number of new nuclear plants was increasing at
an immense and steady rate. In fact, more recent
statistics show 60 plants in the process of being
built, the majority in China and others in Russia,
India, South Korea and Japan. The USA is only
shown as having one actual building project.
However, this list (the VGB Power Tech) includes
numerous ancient projects that were never completed and are therefore de facto building ruins.
Moreover, there are at the present time proposals for about 160 new nuclear power plants
up to the year 2020, 53 of these in China alone
and 35 in the USA, followed by South Korea andRussia. In Europe, the UK heads the list witheight proposed new projects, followed by Italy,
Switzerland, Finland, Rumania and Lithuania.
France, that would like to bless the world withnew nuclear power stations, is itself only planning one new plant. Most European states are notentertaining any concrete nuclear plans.
As a matter of fact the number of nuclear power plants in the world is continually decreasing.
At the present time there are still 436 reactors inoperation. In the next 15 to 20 years more ageing
plants will go offline than new ones coming into
operation. By no means will all declarations ofintent be implemented. The more energy markets
are opened up to free competition, the smaller
the chances are for nuclear energy.
The costs for new plants are also exploding. For example, the building cost of the new
nuclear power plant in Finland’s Olkiluoto has
already increased from 3 to around 5.4 billion
Euros although not even the shell of the building
is standing yet. In addition, there are the unsolved
problems of waste disposal and the high susceptibility of the technology to failure. Today, no
privately run energy conglomerate risks building
a new nuclear power station without government

subsidies and guarantees. It is noticeable thatnew nuclear power stations are built particularly
where the government and the energy industry
form an unholy alliance.
Up to now, nuclear power plants have been
funded by massive public subsidies. For Germany
the calculations roughly add up to over 100 billion Euros and this preferential treatment is stillgoing on today. As a result the billions set aside
for the disposal of nuclear waste and the dismantling of nuclear power plants represent a tax-freemanoeuvre for the companies. In addition theliability of the operators is limited to 2.5 billion
Euros – a tiny proportion of the costs that would
result from a medium-sized nuclear accident. All
things considered nuclear energy proves to bejust as expensive as it is risky.
In addition to the routine arguments about
nuclear energy, there are some new ones. Firstly,
the danger of nuclear proliferation is growing in
proportion to the number of new nuclear power
stations all over the world. There is no insurmountable division between the civil and military use ofthis technology in spite of the efforts on the part of
the International Atomic Energy Agency (IAEA)
to regulate this. The most recent example is Iran.
At the end of the day anyone who does not want
to be regulated cannot be forced to do so. With
the expansion of nuclear energy there is a growing necessity to build reprocessing plants and fast
breeders in order to produce nuclear fuel. Both giverise to the circulation of plutonium leading in turnto the creation of huge amounts of fissile material
capable of making bombs – a horror scenario!
Secondly, an extension of the life span of existing nuclear energy stations, and even more so
the building of new plants, would act as a massive
brake on the development of renewable energies.
The claim that nuclear energy and renewableenergies complement each other is a myth since
not only do they compete for a meagre amountof investment capital and power-lines but at the6same time nuclear plants limit the growth potential particularly of wind energy owing to theirinflexible continuous operation. On windy andlow-consumption days the energy demand inGermany is already covered to a large extent by
the wind energy supply. As the output of existing nuclear power stations (as well as the big
coal-fired power stations) is not reduced at short
notice for economic reasons, the surplus energy
has to be exported to other countries at a loss.
There is method in this madness.
Whatever way you look at it, nuclear energy has
neither the potential to make a decisive contribu-

The Economics of Nuclear Power: An Updatetion to climate change nor is it necessary in order toguarantee energy supply. The exact opposite is true.
Those who want to promote the development of
renewable energy with the aim of producing 100%of the power demand should oppose the buildingof new nuclear plants as well as the life span extension of older ones. Despite the claims about nuclear
energy it is not a suitable interim strategy leading
towards the age of solar energy.

Berlin, January 2010
Ralf Fücks(Chairman of the Heinrich-Böll-Stiftung)Author’s note						 	 

7Author’s note

Since the following text was finalised in
March 2010, there have been a number of new
construction starts and completions of nuclear
plants. The table below shows the seven plants
on which construction has started between
March 2010 and the end of August 2010. Work
has also restarted on the Angra 3 plant in Brazil
on which construction started in 1976 (seeTable 3 for details of the plant). Four units (seeTable 2 for more details) have been completed:

Rajasthan 6 (India), Lingao 3 and Qinshan 2-3(China), and Shin Kori 1 (South Korea). The net
result of these changes is that by August 2010,
there were 59 reactors under construction ofwhich 37 had construction starts after 2005. Of
these 37, 23 are in China, 6 are in Russia, 5 arein South Korea, 2 are in Japan and 1 is in France.
The picture of new orders still being dominatedby a few countries generally using home suppliers and relatively old designs remains.

Nuclear capacity with construction starts between March 2010 and August 2010
Country

Site

Reactor type

VendorSize MW

China

Taishan 2

PWR

Areva

1700

China

Changjiang 1

PWR

China

1000

China

Haiyang 2

PWR

China

1000

China

Fangchenggang 1

PWR

China

1000

Japan

Ohma

BWR

Toshiba1325

RussiaLeningrad 2-2

PWR

Russia1080

RussiaRostov 4

PWR

Russia1080

Source: PRIS Data Base, http://www.iaea.org/programmes/a2/index.html

8

The Economics of Nuclear Power: An Update

Introduction

The severe challenge posed by the need toreduce emissions of greenhouse gases, especiallyin the electricity generation sector, has led torenewed interest in the construction of nuclear
power plants. These would initially replace theaging stock of existing reactors, then meet electricity demand growth, and eventually replacesome of the fossil-fired electricity-generating
plants. They would also be built in new markets
that up to now have not used nuclear power.
In the longer term, the promise is that nuclear
power could take over some of the energy needs
currently being met by direct use of fossil fuels.
For example, nuclear power plants could be used
to manufacture hydrogen, which would replaceuse of hydrocarbons in road vehicles.
The public is understandably confused about
whether nuclear power really is a cheap source ofelectricity. Cost estimates for new nuclear plants
have been escalating at an alarming rate, andin the past decade, construction cost-estimateshave increased five-fold, with every expectationthat costs will increase further as the designs are
firmed up. Yet, in recent years, governments suchas those of the United States, the United Kingdom,
Germany, and Italy have become increasingly
determined in their attempts to maintain existing nuclear plants in service and revive nuclear

ordering, on the grounds that nuclear power is themost cost-effective way to combat climate change.
Utilities are determined to operate their existing
plants for as long as possible and have given verbal support to the need for new nuclear power
plants, but they are reluctant to build new nuclear
power plants without cost- and market guarantees and subsidies. Some of this apparent paradox
is relatively easily explained by the difference between the running costs only of nuclear power,
which are usually relatively low, and the overall
cost of nuclear power – including repayment of theconstruction cost – which is substantially higher.
Thus, once a nuclear power plant has been built,
it may make economic sense to keep the plant inservice even if the overall cost of generation, including the construction cost, is higher than thealternatives. The cost of building the plant is a“sunk” cost that cannot be recovered, and themarginal cost of generating an additional kWh
could be small.
The objective of this report is to identify the
key economic parameters that determine thecost of nuclear electricity, commenting on theirdetermining factors. It shows that without subsidies and guarantees from electricity consumers
and taxpayers, new nuclear power plants will
not be built.

9

1. The world market for nuclear plants:
existing orders and prospects
Over the past decade, there has been increas- in the United Kingdom and the United States
ing talk about a “Nuclear Renaissance” based on were so bad that, a decade ago, it seemed unlikely
two factors. A new generation of nuclear pow- that orders would be possible, so reviving theseer plants, so-called Generation III+, would be markets would be a particular coup.
cheaper and easier to build, safer, and produce
The list of plants currently on order (Tables 2,
less waste (see Appendix 1 for a description of
the Generation III+ designs). Ordering would 3, and 4) suggests that the Renaissance is largely
be not only in countries where nuclear ordering talk and is geographically limited. In January
had not been problematic, such as France, India, 2010, there were 55 plants under constructionand South Korea, but also in countries such as worldwide, with a capacity of 51 GW compared
the United States, the United Kingdom, Italy, to 443 plants already in service with a capacity
as well as Germany, which seem to have turned of 375 GW (Table 1). Of the 32 units on whichaway from nuclear power. The United States construction had started after 2005, all except
two (one each in France
and the United Kingdom
The list of plants currently on orderand Japan) were in China
are particular targets forsuggests that the Renaissance is largely(20), South Korea (6), or
the nuclear industry for atalk and is geographically limited.
Russia (4) (Table 2). All
number of reasons:
except five of these units,
the UK and US programmes are closer to all for China, were supplied by indigenous supplacing orders for Generation III+ designs than pliers. The Western vendors active in Europe
elsewhere in Europe and North America, apart – Westinghouse and Areva NP – have won justfrom Finland and France;
two orders outside China: Areva NP’s Olkiluoto
the United Kingdom and United States are order for Finland and its Flamanville order forseen as pioneers of nuclear power and, therefore, France. These seven orders and the four units
new orders for nuclear plants in these countries ordered from South Korea by the United Arabcarry additional prestige; andEmirates (UAE) in December 2009 are the only
economic experiences with nuclear power ones for Generation III/III+ designs.

© Greenpeace / Jesse Anttila

1. The world market for nuclear plants: existing orders and prospects

10

The Economics of Nuclear Power: An Update

So without China, the order book for new
Russia, like China, has had very ambitious
nuclear power stations would look much weaker. plans to expand nuclear power. In 2008, it had
Most of its orders are being supplied by Chinese plans to commission 26 new nuclear units (aboutcompanies and are based on the French design it 30 GW) by 2025, but by 2009, this target had alreadyordered in 1980 for its Daya Bay site. It remains slipped to 2030 1. Four units dating back to theto be seen whether China has the human and 1980s are listed as still being under construction
financial resources to continue to finance orders and nearly complete, but this has been the situation for a decade or moreat the rate it had in 2008(see Table 3). If the need forand 2009, when work on
The most likely outcome for China, is
new nuclear capacity was
15 new units was started.
that it will continue to place a small
urgent and the financial
The most likely outcome
number of nuclear orders on the inresources were available,
for China, given the need
ternational market – much fewer thanthese units would surely
for China to use its limited
forecast by the Chinese government or
have been completed bycapital resources carefully,
by the nuclear industry – while trying tonow. Reliable informationis that it will continue tobuild up its capability through its own
from Russia on the statusplace a small number ofnuclear power plant supply industry.
of construction at nuclear
nuclear orders on the inplants is difficult to get andternational market – much
fewer than forecast by the Chinese government or these plants may not currently be under construcby the nuclear industry – while trying to build up tion. A particular doubt is the Kursk 5 plant, which
its capability through its own nuclear power plant uses the same technology as the Chernobyl plant
supply industry. The designs it is supplying now and which would be very controversial if brought
on-line.
are too old to be relevant to the West.
Table 1 – Nuclear capacity in operation and under construction: January 2010

1
2

Operating:
Cap MW(no. units)

Construction:
Cap MW(no. units)

Argentina

935 (2)692 (1)

Armenia

376 (1)-

Belgium

5863 (7)-Brazil1766 (2)Bulgaria% elecnuclear (2008)

Technologies 2

Suppliers

6

HWR

Siemens AECL

39

WWER

Russia54

PWR

Framatome

-

3

PWR

Westinghouse
Siemens

1966 (2)1906 (2)33

WWER

RussiaCanada12577 (18)

-

15

HWR

AECL

China

8438 (11)19920 (20)2

PWR, HWR,
WWER

Framatome,
AECL, China,
RussiaTaiwan4949 (6)2600 (2)20

PWR, BWR

GE, 
Framatome

Czech Republic

3678 (6)

-

32

WWER

RussiaNucleonics Week, “Russia Stretches Out Schedule for New Reactor Construction”, March 26, 2009
See Appendix 1 for an overview of the technologies.

1. The world market for nuclear plants: existing orders and prospects

11Operating:
Cap MW(no. units)

Construction:
Cap MW(no. units)% elecnuclear (2008)

Technologies 2

Suppliers

Finland2696 (4)1600 (1)30

WWER, BWR,
PWR

Russia, Asea,
Westinghouse

France63260 (59)1700 (1)76

PWR

Framatome

Germany

20470 (17)-28

PWR, BWR

Siemens

Hungary

1755 (4)

-

37

WWER

Russia2

HWR, FBR,
WWER

AECL, India,
RussiaWWER

Russia3984 (18)2708 (5)Iran-

915 (1)

Japan

46823 (53)1325 (1)25

BWR, PWR

Hitachi,Toshiba, Mitsubishi

South Korea

17647 (20)6520 (6)36

PWR, HWR

Westinghouse,
AECL, S
Korea,

India

Mexico1300 (2)

-

4

BWR

GE

Netherlands

482 (1)-

4

PWR

Siemens

Pakistan

425 (2)300 (1)

2

HWR, PWR

Canada, China

Romania

1300 (2)

18

HWR

AECL

Russia21743 (31)6894 (9)

17

WWER,
RBMK

RussiaSlovak Republic

1711 (4)810 (2)

56

WWER

RussiaSlovenia

666 (1)

-

42

PWR

Westinghouse

South Africa

1800 (2)

-

5

PWR

Framatome

Spain

7450 (8)-18

PWR, BWR

Westinghouse,
GE Siemens

Sweden8958 (10)-42

PWR, BWR

Westinghouse,
Asea

Switzerland

3238 (5)-39

PWR, BWR

Westinghouse,
GE Siemens

Ukraine13107 (15)1900 (2)47

WWER

RussiaUK

10097 (19)-13

GCR, PWR

UK, 
Westinghouse

USA

100683 (104)1165 (1)20

PWR, BWR

Westinghouse,
B&W, CE, GE

WORLD

375136 (443)50955 (55)

Source: IAEA, http://www.iaea.or.at/programmes/a2/

12

The Economics of Nuclear Power: An Update

India ordered a small number of plants from
Western suppliers in the 1960s and 1970s, but
a nuclear weapons test in 1975 using material
produced in a Canadian research reactor led tothe cutting of all contact with Western suppliers. India has continued to build plants using
the 1960s Canadian design it had ordered. These
have a poor record of reliability and frequently
take much longer to build than forecast, so thecompletion dates in Table 2 should be treatedwith scepticism. The United States also broke offcooperation in 1998 after further weapons tests
but in 2005, India and the United States negotiated a deal over technological cooperation in civil
nuclear power. Canada also resumed sales ofnuclear material in 2005. Since then Rosatom of
Russia (up to 4 WWER-1200 units), Westinghouse(up to 8 AP1000s), Areva (up to 6 EPRs) and
GE-Hitachi (up to 8 ABWRs) have all claimed
they have agreements to supply nuclear plants
there, but none of these have been turned into
firm orders. India’s own nuclear industry expects
to build a large number of new plants using avariety of technologies, including fast reactors,
heavy-water reactors, and thorium-fueled plants.
The Indian government has set a target of 63,000
MW of new nuclear capacity to be in service by2032. It would be astonishing, considering its pastrecord, if India even got close to meeting thistarget.

Table 2 – Nuclear power plants under construction worldwide ordered from 1999 onwards

Site

Reactortype

VendorSize MW

Construction
startConstruction
stage (%)

Expected
operation

China

Fangjiashan 1

PWR

China

1000

2008

0

-

China

Fangjiashan 2

PWR

China

1000

2009

0

-

Country

China

Fuqing 1

PWR

China

1000

2008

0

-

China

Fuqing 2

PWR

China

1000

2009

0

-

China

Haiyang 1

PWR

China

1000

2009

0

-

China

Hongyanhe 1

PWR

China

1000

2007

20

-

China

Hongyanhe 2

PWR

China

1000

2008

0

-

China

Hongyanhe 3

PWR

China

1000

2009

0

-

China

Hongyanhe 4

PWR

China

1000

2009

0

-

China

Lingao 3

PWR

China

1000

2005

60

2010

China

Lingao 4

PWR

China

1000

2006

50

2010

China

Ningde 1

PWR

China

1000

2008

10

-

China

Ningde 2

PWR

China

1000

2008

5

-

China

Ningde 3

PWR

China

1000

2010

5

-

China

Qinshan 2-3

PWR

China

610

2006

50

2010

China

Qinshan 2-4

PWR

China

610

2007

50

2011

China

Sanmen 1

PWR

W’house

1000

2009

10

-

China

Sanmen 2

PWR

W’house

1000

2009

10

-

China

Taishan 1

PWR

Areva

1700

2009

0

-

China

Yangjiang 1

PWR

W’house

1000

2009

10

-

China

Yangjiang 2

PWR

W’house

1000

2009

0

-

TaiwanLungmen 1

ABWR

GE

1300

1999

57

2011

1. The world market for nuclear plants: existing orders and prospects

13

VendorSize
MW

Construction
startConstruction
stage (%)

Expected
operation

ABWR

GE

1300

1999

57

2012

EPR

Areva

1600

2005

40

2012

Flamanville 3

EPR

Areva

1700

2007

25

2012

Kaiga 4

Candu

India

202

2002

97

2010

India

Kudankulam 1

WWER

Russia

917

2002

90

2011

India

Kudankulam 2

WWER

Russia

917

2002

79

2011

India

PFBR

FBR

India

470

2005

37

-

India

Rajasthan 6

Candu

India

202

2003

92

2010

Japan

Shimane 3

BWR

Toshiba

1325

2007

57

2011

South Korea

Shin Kori 1

PWR

S Korea

960

2006

77

2010

South Korea

Shin Kori 2

PWR

S Korea

960

2007

77

2011

South Korea

Shin Kori 3

PWR

S Korea

1340

2008

29

2013

South Korea

Shin Kori 4

PWR

S Korea

1340

2009

29

2014

South Korea

Shin Wolsong 1

PWR

S Korea

960

2007

49

2011

South Korea

Shin Wolsong 2

PWR

S Korea

960

2008

49

2012

Chasnupp 2

PWR

China

300

2005

25

2011

Site

Reactortype

TaiwanLungmen 2

Finland

Olkiluoto 3

FranceIndia

Country

Pakistan
RussiaBeloyarsky 4

FBR

Russia

750

2006

12

-

RussiaLeningrad 2-1

WWER

Russia

1085

2008

0

-

RussiaNovovoronezh 2-1

WWER

Russia

1085

2008

5

-

RussiaNovovoronezh 2-2

WWER

Russia

1085

2009

0

-

TOTAL

40778

Sources: PRIS Data Base, http://www.iaea.org/programmes/a2/index.html; Nuclear News, world list of nuclear plants
Note: Includes only units larger than 100 MW. Construction stage is as reported by Nuclear News in March 2009

South Korea has continued to order nuclear
plants throughout the past two decades – five inthe past four years – and it already gets 36% of its
electricity from nuclear plants (see Table 2). The
six units under construction may increase this to50%, leaving little scope for many more orders forthe home market. This may account for the decision to move into export markets and winning
four orders from the United Arab Emirates at alow reported price.
Japan is another country that has consistently
forecast large increases in nuclear capacity not
matched by actual orders. Japanese companies
supply these plants using technology licensed

from Westinghouse and GE. It may take up to 20
years to get approval to build at sites in Japan,
although once construction starts, completion isusually quick (four years typically) and does not
usually go beyond schedule. A series of accidents
at plants in Japan, often badly mishandled, have
led to an increase in public concern about nuclear
power, and finding sites for further plants is likely
to be difficult. Only one plant was under construction at the start of 2010 (see Table 2) and it seems
likely that no more than a trickle of orders will beplaced for Japan.
Table 3 shows that there are 17 uncompleted units on which construction started

14

The Economics of Nuclear Power: An Update

before 1990 that might still be brought on-line, in 2007, when it was expected the plant would be
but on which work is not necessarily being complete by 2013 for $2.5 billion.
actively done. For these, the quoted degree ofcompletion may be misleading. Plants reported
In 2009, the Tennessee Valley Authority, theto be less than 33% complete are likely to have utility that owns Watts Bar, also began to investiseen only site preparation with no actual reactor gate the possibility of restarting construction of
construction. In addition, the completion time two units at its Bellefonte site in Alabama (USA).
for unit under construcConstruction on this twotion in Taiwan – orderedunit site started in 1974,
Completing work on designs suchin 1996 when compleand when work was haltas those at Bellefonte and Watts Bar
tion was expected in 2004
ed in the mid-1980s 5, workthat are now about 40 years old raises
was estimated to be more
– has slipped by eightparticular issues, given that it isthan 90% complete on unit
years. The Watts Bar reachighly unlikely these designs would be
1 and about 60% complete
tor in Tennessee (USA) is
licensable if they were submitted to theon unit 2. Completing worka particularly interesting
safety authorities now.
on designs such as those at
example. Construction of
Bellefonte and Watts Bar
it and its twin were started in 1973 but work was continually delayed. Unit that are now about 40 years old raises particular
1 was finally completed in 1996 at a cost of more issues, given that it is highly unlikely these designs
than $6 billion 3, but work on unit 2 was effective- would be licensable if they were submitted to thely halted in 1985 when construction was reported safety authorities now.
to be 90% complete 4. Work restarted on the plant

3
4
5

Chattanooga Times, “Tennessee: Estimates Rise for Nuclear Plant”, section A1, December 12, 2008.
http://www.tva.gov/environment/reports/wattsbar2/seis.pdf
http://web.knoxnews.com/pdf/082708bellefonte-reinstatement.pdf

1. The world market for nuclear plants: existing orders and prospects

15

Table 3 – Nuclear power plants on which construction started before 1990
Construction
startConstruction(%)

Expected
operation

692

1981

87

2010

Siemens

1275

1976

10

Russia

953

1987

0

Size MWCountry

Site

Tech

VendorArgentina

Atucha 2

HWR

Siemens

BrazilAngra 3*

PWR

Bulgaria

Belene 1*

WWER

Bulgaria

Belene 2*

WWER

Russia

953

1987

0

Iran

Bushehr

WWER

Russia

915

1975

99

Cernavoda 3*

Candu

AECL

655

1983

23

Romanianet

Romania

Cernavoda 4*

Candu

AECL

655

1983

12

Romania

Cernavoda 5*

Candu

AECL

655

1983

8

RussiaBalakovo 5*

WWER

Russia

950

1986

High

RussiaKalinin 4

WWER

Russia

950

1986

High

RussiaKursk 5*

RBMK

Russia

925

1985

High

RussiaVolgodonsk 2

WWER

Russia

950

1983

High

Slovakia

Mochovce 3

WWER

Russia

405

1983

40

Slovakia

Mochovce 4

WWER

Russia

405

1983

30

2010

2010

UkraineKhmelnitsky 3

WWER

Russia

950

1986

30

2015

UkraineKhmelnitsky 4

WWER

Russia

950

1987

15

2016

USA

Watts Bar 2

PWR

W’house

1165

1972

70

2012

TOTAL

14403

Sources: PRIS Data Base, http://www.iaea.org/programmes/a2/index.html ; Nuclear News, world list of nuclear plants
Note: Construction work has stopped on reactors marked *Table 4 – Nuclear power plant orders on which construction had not started by Jan 1 2010
Country

Site

Tech

VendorSize
MW net

Order
date

China

Taishan 2

EPR

Areva

1700

2008

UAE

Unknown

AP-1400

S Korea

4 x 1400

2009

Source: Various press reports© Fotolia

16

The Economics of Nuclear Power: An Update

2. Key determinants of nuclear economics

There are several important determinantsof the cost of electricity generated by a nuclear
power plant (see Table 5). Some of these are
intuitively clear while others are less obvious.
Areva NP, the French vendor of nuclear power
plants, estimates 6 that 70% of the cost of a kWhof nuclear electricity is accounted for by the“fixed” costs from the construction process, 20%
by “fixed” operating costs, and the other 10% by“variable” operating costs. The main fixed con-struction costs are the costs of paying intereston the loans and repaying the capital, but thedecommissioning cost is also included. The cost
per kWh is also determined by the reliability ofthe plant: The more reliable it is, the more unitsof output it will produce, over which amountthe fixed costs can be spread. The main runningcosts are the costs of operation, maintenance,and repair rather than fuel.

Table 5 – Nuclear economics – cost elements (based on Areva NP)
Share
70%

Fixed costs for construction: interest on loans/repaying capital

20%

Fixed operations (cost/kWh): depends on reliability of plant (e.g., load factor)

10%

Variable operations: operation, maintenance, repair, fuelNot included

6

Description

Decommissioning, waste disposal and management, risk of meltdown, environmental and human harm

http://www.areva.com/servlet/BlobProvider?blobcol=urluploadedfile&blobheader= application%252Fpdf&blobkey=
id&blobtable=Downloads&blobwhere=1246874807296&filename=Overview_June_2009%252C0.pdf

2. Key determinants of nuclear economics                                                                                                                               17Prior to looking at these costs in detail, it is im2.1.1. Unreliability of data
portant to note that there is a significant mismatch
Many of the quoted construction cost forebetween the interests of commercial concernsand society in general. Huge costs that will only casts should be treated with scepticism. The mostbe incurred far in the future have little weight in reliable indicator of future costs has generallycommercial decisions because such costs are been past costs 7. However, most utilities are not“discounted” (see Appendix 3). This means that required to publish properly audited construcwaste disposal costs and decommissioning costs, tion costs and have little incentive to present
which are at present no more than ill-supported their performance in anything other than a good
guesses, are of little interest to commercial com- light. However, US utilities were required to pubpanies. From a moral point of view, the current lish reliable accounts of the construction costs ofgeneration should be extremely wary of leaving their nuclear plants for the economic regulator
such an uncertain, expensive, and potentially dan- (who only allowed cost recovery from consumgerous legacy to a future generation to deal with ers for properly audited costs) and past US
when there are no ways of reliably ensuring that costs are reliable. The cost of the Sizewell B (UK)plant is also reasonably
the current generation can
Huge costs that will only be incurred
well-documented because
bequeath the funds to deal
far in the future have little weight init had few other activities
with them, much less bearcommercial decisions because suchin which the construction
the physical risk. Similarly,
costs are “discounted”.
cost could be “disguised.”
the accident risk also plays
This means that waste disposal costs
no part in decision-making
and decommissioning costs, which are
The next best option
because the companies
at present no more than ill-supported
is the price quoted in calls
are absolved of this risk byguesses, are of little interestfor tenders. While theinternational treaties thatto commercial companies.
actual cost of a nuclear
shift the risk to taxpayers.

2.1.	Construction cost and time
Construction cost is the most widely debatedparameter, although other parameters, such as
the cost of capital and the reliability of the plant,
are of comparable importance to the overall costof each kWh of electricity. To allow costs to becompared, utilities generally quote the “overnight” cost, which, as well as the cost of the plant,
includes the cost of the first charge of fuel but
not the interest incurred on borrowings during
the construction of the plant, usually known asinterest during construction (IDC). To allow comparisons between reactors with different output
capacities, costs are often quoted as a cost per
installed kW. Thus, a nuclear power plant costing $2,400 million with an output rating of 1200
MW would have a cost of $2,000/kW. There are anumber of factors that explain why there is suchcontroversy about forecasts of construction cost.
7

plant is generally higher(often significantly) thanthe contract price, the vendor should at least haveto fully price the order. If the order is a genuine“turnkey” order – that is, a fixed price order inwhich the customer pays only the contract priceno matter what the actual costs are – the vendor
has a particular incentive to make the bid price asaccurate as possible.
Turnkey terms are only possible where thevendor is confident that they can control all aspects of the total construction cost. The current
generation of gas-fired power plants, combined
cycle gas turbine (CCGT) plants, are often soldunder turnkey terms because they are largely
built in factories controlled by the vendor andrequire relatively little on-site work. In the mid1960s, the four major US nuclear vendors sold atotal of 12 plants under turnkey terms, but lost
massive amounts of money because of their ina-

Estimates of future costs have almost invariably been overoptimistic, based on faulty expectations about learning,
scale, and innovation effects that have not been reflected in costs.

18

bility to control costs. Since then, it is unlikely thatany vendor has risked offering a complete planton turnkey terms. Note that individual items ofequipment may be purchased on turnkey terms,
but any price for a nuclear plant quoted as being on turnkey terms should be regarded withconsiderable skepticism. The Olkiluoto order isusually described as “turnkey”, with Areva being
responsible for management of the construction.
However, as is described in Section 3.1., Areva
was in dispute with the customer, Teollisuuden
Voima Oyj (TVO), over the terms of the contractand specifically which party pays for cost-overruns. Note, some vendors use the term “turnkey”
rather loosely and they sometimes mean no morethan that the contract covers the whole plant.
Indicative prices quoted by vendors also mustbe treated with skepticism. GE-Hitachi (GEH),
has acknowledged that vendors have not been
careful enough in giving indicative prices and theoveroptimistic prices quoted have become counterproductive. The GEH president and CEO, Jack
Fuller, said: “When reactor construction projects
cost much more than projected, that undermines
the public’s confidence in the industry.” 8
Prices quoted by those with a vested interest in the technology but no influence over prices– including industry bodies such as the World
Nuclear Association and equivalent national
bodies – clearly must be viewed with skepticism.
Prices quoted by international agencies, such as
the Nuclear Energy Agency, also must be treated with care, particularly when they are based on
indicative rather than real costs. Generally, thesecosts are provided by national governments,
which may have their own reasons to show nuclear power in a good light, and which generally do
not base their figures on actual experience.
Forecasts of construction costs have beennotoriously inaccurate, frequently being a seri-

The Economics of Nuclear Power: An Update

ous underestimation of actual costs and, counterto experience with most technologies – where
so-called learning, scale economies, and technical progress have resulted in reductions in thereal cost of successive generations of technology– real construction costs have not fallen and havetended to increase through time. There is also
some inevitable variability from country to country as a result of local labour costs and the cost of
raw materials such as steel and concrete.

2.1.2. Difficulties of forecasting
There are a number of factors that makeforecasting construction costs difficult. First, allnuclear power plants currently on offer requirea large amount of on-site engineering, the cost ofwhich might account for about 60% of the total construction cost, with the major equipment items– such as the turbine generators, the steam generators, and the reactor vessel – accounting fora relatively small proportion of total cost 9. Large
projects involving significant amounts of on-siteengineering are notoriously difficult to manage and to control costs on. For example, in the
United Kingdom, the costs of the Channel Tunnel
and the Thames Barrier were well above forecast
costs. Some Generation IV designs are expected
to be largely factory-built and costs are expected
to be much easier to control in a factory.
Second, there are also site-specific factorsthat might make a significant difference to costs,
for example the method of cooling. GEH CEO
Fuller said that the problem with such [generic]estimates was that no one made clear “what the
number represented […] Did it include fuel? Was
the plant on saltwater or freshwater?” Danny
Roderick, GEH senior vice president, nuclear
plant projects, said: “GEH had seen plant costschange by $1 billion depending on whether theplant is cooled by saltwater or freshwater.” 10

Nucleonics Week, “GEH: Cost Estimates Did Industry a ‘Disservice,’” September 17, 2009.
As a result of the difficulty of controlling construction costs, the World Bank does not to lend money for nuclear
projects. See Environmental Assessment Sourcebook: Guidelines for Environmental Assessment of Energy andIndustry Projects, Volume III, World Bank Technical Paper 154 (Washington, DC: World Bank, 1991).
10 Nucleonics Week, “GEH: Cost Estimates.”

89

2. Key determinants of nuclear economics                                                                                                                               19Third, costs increase if design changes arenecessary, for example if the original detailed design turns out to be poor, or the safety regulator
requires changes in the design, or the design was
not fully worked out before construction started.
In response to these problems, plant constructors now aim to get full regulatory approval
before construction starts, as with the proposed
US combined Construction and Operation
Licenses (COL), and they require designs to be
as fully worked out as reasonably possible before
construction starts. In practice, vendors often
claim their designs are complete, as was the casewith the Olkiluoto plant under construction in
Finland (see Section 3.1.). But even after four
years of construction, in 2009, it had become
clear the design was still far from complete. The
risks posed by design changes cannot be entirely
removed, especially with new designs whereby
unanticipated problems might be introduced by
the construction process or whereby the regulator cannot agree with design details as they arefilled in. For example, at the Olkiluoto plant by
2009, the regulator expressed serious concerns
about the adequacy of the proposed control andinstrumentation systems. Without major changes, the regulator was not willing to license theplant (see Section 3.1.).
Experiences within operating reactors mightalso lead to the need for changes in the design
after construction has started. For example, amajor nuclear accident would necessarily lead toa review of all plants under construction (as well
as all operating plants) and important lessons
could not be ignored simply because licensing approval of the existing design had alreadybeen given.

2.1.3. Learning, scale economies,
and technical progress
The expectation for most technologies is thatsuccessive generations of design will be cheaperand better than their predecessors because offactors such as learning, economies of scale, andtechnical change. How far nuclear technology

has improved through time is a moot point, butcosts have clearly not fallen. The reasons behind
this are complex and not well understood, but
factors that are often quoted are increased regulatory requirements (note, the standards have notincreased, but the measures found to be necessary
to meet these standards have) and unwise costcutting measures with first-generation reactors.
The paucity of orders for current generations of reactors, especially those with properly
documented costs, makes it difficult to knowwhether costs have stabilised yet, let alone
begun to fall. However, “learning” – in otherwords, improvements in performance throughrepetition – and scale economies are two-way
processes. In the 1970s, the major reactor vendors were receiving up to 10 orders per year.
This allowed them to set up efficient production lines to manufacture the key components
and allowed them to build up skilled teamsof designers and engineers. How much these
economies of number produced reduced costs
is difficult to estimate. A Nuclear Energy Agency
report from 2000 suggests that the intuitive expectation that economies of number would belarge may not be accurate. It stated:11
The ordering of two units at the same time
and with a construction interval of at least 12
months will result in a benefit of approximately
15% for the second unit. If the second unit is partof a twin unit the benefit for the second unit isapproximately 20%. The ordering of additional
units in the same series will not lead to significantly more cost savings. The standardisation
effect for more than two units of identical design
is expected to be negligibly low.
When the UK Performance and Innovation
Unit (PIU) of the Cabinet Office examined nuclear power economics in 2002, it was provided
with forecasts of costs from British Energy (thenuclear power plant owner) and BNFL (theplant vendor) that were based on “a substantial
learning and scale effects from a standardised
programme.” The PIU was sceptical about theextent of learning, acknowledging that learning

11 Nuclear Energy Agency, Reduction of Capital Costs of Nuclear Power Plants (Paris: OECD, 2000), p. 90.

20

was likely to occur but that its impact could be
limited. It stated:12
The pace and extent of learning may however be slower for nuclear than for renewables
because:relatively long lead times for nuclear
power mean that feedback from operating experience is slower;
relicensing of nuclear designs further
delays the introduction of design changes; andthe scope for economies of large-scale
manufacturing of components is less for nuclear
because production runs are much shorter thanfor renewables, where hundreds and even thousands of units may be installed.
The major reactor vendors have received only
a handful of orders in the past 20 years, their own
production lines have closed, and skilled teams
have been cut back. Westinghouse had received
only one order in the past 25 years before theorder for four units from China in 2008. Even
the French vendor Areva received its first orderin about 15 years with its order for Finland. For
new orders, large components would generally
have to be subcontracted to specialist companies and built on a one-off basis, presumably athigher costs in countries such as Japan and, forthe future, China13. There are now acknowledged
to be major shortages in component manufacturing facilities. For example, by the end of 2009,
only one facility in the world, Japan Steel Works,
could cast large forgings for certain reactor pressure vessels.
Skills shortages are also becoming acute. A
report for the German Environment Ministrystated: 14
The nuclear skills and competence gap isan internationally well established and recognised problem. Numerous initiatives havebeen launched on national and international
scale in order to reverse the trend. However,

The Economics of Nuclear Power: An Update

apparently, the results remain far short of thenecessary employment levels for all stakeholders involved. The number of nuclear graduates
and technicians is insufficient and many graduates do not enter or quickly leave the nuclear
sector. In-house training only partially compensates for the problem since the nuclear industry
has to compete in a harsh market environment
with many other sectors that lack scientists,
engineers and technicians.

2.1.4. Construction time
An extension of the construction time beyond
that forecast does not directly increase the construction costs, although it will tend to increaseinterest during construction and often is a symptom of problems in the construction phase suchas design issues, site management problems, or
procurement difficulties that will be reflected inhigher construction costs. However, the impact
on the utility – if it is a relatively small utility forwhich the new plant would represent a major
addition to capacity – could be severe, especially
if the output is already contracted.
The Olkiluoto plant was expected to comeon-line in May 2009 when the construction contracts for it were signed. However, by May 2009,
the plant was still nearly four years from completion. Its output had already been contracted to
the Finnish energy-intensive industry. So, theutility will have to buy “replacement power” tosupply its customers with the power they had
contracted from the Nordic wholesale electricity
market until the plant is complete, at whatever
cost is prevailing in the Nordic market. If the
supply-demand balance is tight, for example if
there is a dry winter that restricts the amountof hydroelectricity availability, this cost could
be far higher than the contracted sale price. The
utility is unlikely to be able to absorb losses forlong if the Nordic market price is significantly

12 Performance and Innovation Unit, The Energy Review, Cabinet Office (London: 2002), p. 195,
http://www.strategy.gov.uk/downloads/su/energy/TheEnergyReview.pdf
13 For example, if the Flamanville EPR is ordered, the pressure vessel would probably be manufactured in Japan.
14	M. Schneider, S. Thomas, A. Froggatt, and D. Koplow, World Nuclear Industry Status Report 2009, German Federal
Ministry of Environment, Nature Conservation and Reactor Safety (2009), 
http://www.bmu.de/files/english/pdf/application/pdf/welt_statusbericht_atomindustrie_0908_en_bf.pdf

2. Key determinants of nuclear economics                                                                                                                               21higher than the price at which it had contracted
to sell the output of Olkiluoto for.
Overall lead time – from the time of the decision to build the plant to its commercial operation(i.e., after the initial testing of the plant has been
completed and its operation handed over by
the vendor to the owner) – is generally much
longer than the construction time. For example, the decision to build the Sizewell B nuclear
power plant in Britain was taken in 1979, butconstruction did not start until 1987 (becauseof delays not only from a public inquiry but also
from difficulties in completing the design). The
plant only entered commercial service in 1995,
so the total lead-time was 16 years. The cost of
the preconstruction phase is generally relatively low compared to construction, unless thereactor is the “first-of-a-kind”, where design andsafety approval could prove expensive. However,for a generating company operating in a competitive environment, this long delay and therisks it entails – such as failure at the planninginquiry stage or cost escalation from regulatory
requirements – is a major disincentive to choose
nuclear.

2.2.	Cost of capitalThis is the other element – construction costin capital charges (see Appendix 2). Generally,large projects are financed through a combination of debt (borrowing from banks) and equity(self-financing from income). For debt, the costof capital will depend on the prevailing “risk-free”
interest rate, for example, the rate paid by treasury
bonds, plus a risk factor to represent the degreeof risk involved in the project, plus of course thebank’s margin and costs.
For equity, it is often suggested that large
companies with substantial resources can easily pay for large investments from income withlittle need for borrowing. However, essentially by financing investment from equity, thecompany is asking shareholders to defer sums
that could have been paid immediately as div-

idends. This money will be invested in the
project and, in the long-term, will be paid backto the shareholders as profits from the project.
To compensate the shareholders for the delay
in receiving their income, the company must
pay the interest that shareholders could haveearned if they had been paid the money andinvested it in low-risk investments plus a premium to reflect the risk that is being taken with
their money (the project might not make thereturn on investment it was expected to). The
cost of equity is therefore generally higher thanthe cost of debt.
If banks are unwilling to lend, replacing borrowing with equity is not likely to be an option.
Essentially this would mean a company was
asking its shareholders to lend money to the company for a project the banks would not touch.
Shareholders may therefore oppose funding oflarge projects with too large an element of equity
funding. Equally, banks will not look kindly on
loan applications if it seems the company is notprepared to risk its own money.
It is particularly revealing that in the UnitedStates, when the Nuclear Power 2010 programme
was launched, it was expected that projects would
be financed in equal measure by debt and equity.
By 2008, it was clear that the companies were
expecting to cover as much of the project cost byborrowing as possible – backed by federal loan
guarantees. The banks also strongly stated theywould be willing to lend money only if the coverage by loan guarantees was very comprehensive.
As noted in Section 4, six of Wall Street’s largest
investment banks informed the US Departmentof Energy (USDOE) that they were unwilling toextend loans for new nuclear power plants unlesstaxpayers shouldered 100% of the risks 15.
The real (net of inflation) cost of capital varies
from country to country and from utility to utility,
according to the country-risk and the credit-ratingof the company. There will also be a huge impact
from the way in which the electricity sector isorganised. If the sector is a regulated monopoly,

15 Investors’ comments in response to DOE notice of proposed rulemaking, July 2, 2007.

22

The Economics of Nuclear Power: An Update

the real cost of capital could be as low as 5 to 8%, less than for shareholder companies, and using
but in a competitive electricity market, it is likely equity might have been easier. The real cost of
to be at least 15%. Thus, for Florida and Georgia, capital – that is, the annual interest rate for borfor example, where the regulator is allowing rowing, net of inflation – for a developed country
the utilities to begin to recover the cost of new was generally in the range of 5 to 8%.
nuclear power plants in regulated electricity tariffs even before construction starts, the utility is
In an efficient electricity market, the risk ofless dependent on loan guarantees being offered investment would fall on the generation company,
to borrow money at low rates. The Georgia Public not the consumers, and the cost of capital would
Service Commission accepted Georgia Power’s, reflect this risk. For example, in 2002 in Britain,
which owns 45.7% of the Vogtle project, request about 40% of the generating capacity was owned
to recover its financing costs for its $6.4 billion by financially distressed companies (aboutshare of the 2234-MW nuclear project through half of this was the nuclear capacity) and several“construction work-in-progress” beginning in companies and banks lost billions of pounds on
2011 16. The assurance of cost recovery means that investments in power stations that they had madethe owners have claimed it will proceed with con- or financed. In these circumstances, a real cost of
struction even if it does not
capital of more than 15%
receive loan guarantees.
seems well-justified. If the
In an efficient electricity market,
It has also reduced therisks were reduced – forthe risk of investment would fall on
expected cost of Georgia
example if there were govthe generation company, not thePower’s share, including
ernment guarantees on the
consumers, and the cost of capitalfinancing up to $4.529
market for power and thewould reflect this risk.
billion 17.
price – the cost of capitalwould be lower, but these
It is clear that if the largest element of cost in would represent a government subsidy (state aid)
nuclear power are the capital charges, more than and it is not clear they would be acceptable under
doubling the required rate of return will severely European Union law.
damage the economics of nuclear power. There
2.3.	Operating performance
is no “right” answer about what cost of capitalshould be applied. When the electricity industry
For a capital-intensive technology like nuclear
was a monopoly, utilities were guaranteed fullcost recovery. In other words, whatever money power, high utilisation is of great importance, sothey spent, they could recover from consumers. that the large fixed costs (repaying capital, paying
This made any investment a very low risk to those interest, and paying for decommissioning) can
providing the capital because consumers were be spread over as many saleable units of output
bearing all the risk. The cost of capital varied as possible. In addition, nuclear power plants
according to the country and whether the com- are physically inflexible and it would not be wisepany was publicly or privately owned. Publicly to start up and shut down the plant or vary theowned companies like Vattenfall, the Swedish output level more than is necessary. As a result,state-owned utility, generally have a high credit nuclear power plants are operated on “base load”,
rating and therefore the cost of capital is lower for except in the very few countries (e.g., France)them than for companies partly or wholly owned where the nuclear capacity represents such a highby private shareholders, like the two main German proportion of overall generating capacity that thisutilities, E.ON and RWE. For publicly owned com- is not possible. A good measure of the reliability ofpanies, shareholder pressure was also generally the plant and how effective it is at producing sale16 Platts Global Power Report, Georgia PSC Approves Two Nuclear Reactors by Georgia Power, and a Biomass
Conversion, March 19, 2009.
17 Nucleonics Week, “Georgia Power Lowers Estimate for New Vogtle Units”, November 11, 2009.

2. Key determinants of nuclear economics                                                                                                                               23able output is the “load factor” (“capacity factor”
in US parlance). The load factor is calculated as
the output in a given period of time expressed asa percentage of the output that would have been
produced if the unit had operated uninterrupted
at its full-design output level throughout theperiod concerned 18. Generally, load factors arecalculated on an annual or a lifetime basis. Unlike
construction cost, the load factor can be precisely
and unequivocally measured and load factor

tables are regularly published by the trade press
such as Nucleonics Week and Nuclear Engineering
International as well as by the International
Atomic Energy Agency (IAEA). There can be dispute about the causes of shutdowns or reduced
output levels, although from an economic pointof view, the fact that output is not being produced
is of less importance than why it is not being produced.

Table 6 – Operating performance of German nuclear power plants
Commercial
operation

Load factor
2008 (%)

Lifetime load factor
to end of 2008 (%)

Biblis A

2/197582.6

65.2

Biblis B

1/1977

95.2

67.7

Brokdorf

12/1986

92.4

88.5

Brunsbüttel

2/19770.0

53.7

Emsland

6/198893.3

93.3

Grafenrheinfeld

6/198287.2

86.2

Grohnde2/1985

88.3

90.6

Gundremmingen B

7/1984

85.7

82.6

Gundremmingen C

1/198587.7

80.4

Isar 1

3/197998.3

79.3

Isar 2

4/198893.2

89.6

Krümmel

3/19840.0

71.6

Neckarwestheim 1

12/1976

54.9

79.5

Neckarwestheim 2

4/198993.0

92.7

Philippsburg 1

3/198078.4

79.0

Philippsburg 2

4/1985

88.7

88.2

Unterweser

9/1979

78.7

79.6

Plant

Source: IAEA, http://www.iaea.or.at/programmes/a2/
Note: The Krümmel and Brunsbüttel plants were closed for the whole of 2008

Table 6 shows the 2008 and the lifetime loadfactors for German nuclear power plants. It
shows a wide range of reliability with three plants

having a lifetime load factor of more than 90%,
while three units have a lifetime load factor ofless than 70%.

18 Note that where reactors are derated, some organisations (e.g., the IAEA) quote the load factor on the authorised
output level rather than the design level. While this may give some useful information on the reliability of the plant,
for economic analysis purposes, the design rating should be used because that is what the purchaser paid to receive.

24

As with construction cost, load factors of operating plants have been much lower than forecast.
The assumption by vendors and those promoting
the technology has been that nuclear plants are
extremely reliable, with the only interruptions toservice being for maintenance and refueling (somedesigns of plant such as the AGR and Candu arerefueled continuously and need to only shut down
for maintenance), thereby giving a load factors of
85 to 95%. However, performance was poor and inaround 1980, the average load factor for all plants
worldwide was about 60%. To illustrate the impact
on the economics of nuclear power, if we assume
fixed costs represent two-thirds of the overall costof power if the load factor is 90%, then the overall
cost would go up by a third if the load factor was
only 60%. To the extent that poor load factors arecaused by equipment failures, the additional costof maintenance and repair resulting would further
increase the unit cost of power. In a competitivemarket, a nuclear generator contracted to supply
power that is unable to fulfill its commitment islikely to have to buy the “replacement” power for
its customer, potentially at very high prices.
However, from the late 1980s onwards, thenuclear industry worldwide has made strenuous efforts to improve performance. Worldwide,
load factors now average more than 80% and,for example, the United States now has an average of nearly 90% compared to less than 60% in
1980, although the average lifetime load factor of
America’s nuclear power plants is still only 70%.
Only seven of the 414 operating reactors withat least a year’s service and that have full performance records have a lifetime load factor in excessof 90%, and only the top 100 plants have a lifetime load factor of more than 80%. Interestingly,
the top 13 plants are sited in only three countries: six in South Korea, five in Germany, andtwo in Finland.
New reactor designs may emulate the level ofreliability achieved by the top 2% of existing reactors, but, equally, they may suffer from “teethingproblems” like earlier generations. The French

The Economics of Nuclear Power: An Update

experience in the late 1990s with the N4 design isparticularly poignant. Note that in an economic
analysis, the performance in the first years of operation – when teething problems are likely toemerge – will have much more weight than thatof later years because of the discounting process. Performance may decline in the later yearsof operation as equipment wears out and has tobe replaced, and improvements to the design
are needed to bring the plant in line with current
standards of safety. This decline in performance
will probably not weigh very heavily in an economic analysis because of discounting. Overall, anassumption that reliability of 90% or more seems
hard to justify on the basis of past experiences.

2.4.	Non-fuel operations
and maintenance costs
Many people assume that nuclear power
plants are essentially automatic machinesrequiring only the purchase of fuel and havevery low running costs. As a result, the non-fueloperations and maintenance costs are seldom
prominent in studies of nuclear economics.
As discussed below, the cost of fuel is relatively low and has been reasonably predictable.
However, the assumption of low running costs
was proved wrong in the late 1980s and early
1990s when a small number of US nuclear power
plants were retired because the cost of operating them (excluding repaying the fixed costs)
was found to be greater than the cost of building
and operating a replacement gas-fired plant. It
emerged that non-fuel O&M costs were on average in excess of $22/MWh, while fuel costs werethen more than $12/MWh 19. Strenuous efforts
were made to reduce non-fuel nuclear O&M
costs and by the mid-1990s, average non-fuelO&M costs had fallen to about $12.5/MWh andfuel costs to $4.5/MWh. However, it is important to note that these cost reductions wereachieved mainly by improving the reliability ofthe plants rather than actually reducing costs.
Many O&M costs (the cost of employing thestaff and maintaining the plant) are largely fixedand vary little according to the level of output of

19 For statistics on O&M costs, see http://www.nei.org/index.asp?catnum=2&catid=95

2. Key determinants of nuclear economics                                                                                                                               25the plant. So, the more power that is produced,
the lower the O&M cost per MWh. The threatof early closure on grounds of economics has
now generally been lifted in the United States.
It is also worth noting that British Energy,
which was essentially given its eight nuclear power plants when it was created in 1996, collapsed
financially in 2002 because income from operation of the plants barely covered operating costs.
This was in part due to high fuel costs, especiallythe cost of reprocessing spent fuel – an operation
only carried out now in Britain and France (seebelow). Average O&M costs for British Energy’s
eight plants, including fuel, varied between about
1.65 2.0p/kWh from 1997-2004. However, in every
following year, the operating costs increased. In
the last full year for which data was published,2007/08, the cost was 3p/kWh and in the firstsix months of 2008/09, the cost was 4.13p/kWh(the company was taken over then by the Frenchutility, EDF, and operating cost figures are notpublished).

2.5. Fuel cost
The cost of fuel, about 5% of the total cost of
power, includes the cost to mine the uranium,“enrich” it (increase the percentage of the useful uranium isotope), fabricate it into fuel, store
it after use, and dispose of it in a safe repository,
where it must remain isolated from the environment for several hundred thousand years. The
costs other than the purchase cost of fuel are notdiscussed further here. Fuel costs have fallen as
the world uranium price was low from the mid1970s (around $12/lb of U3O8) to around 2000,
after which prices rose to about $150/lb (seeTable 7). Subsequently, spot prices fell to lessthan $50/lb by the end of 2009. These spot prices
are a little misleading as the spot market is very“thin” and only a small proportion of uranium
is bought and sold on this market, with the vast
majority being sold under long-term bilateralcontracts. US fuel costs average about 0.25p/kWh,but these are arguably artificially low because the
US government assumes responsibility for disposal of spent fuel in return for a flat fee of $1/
MWh (0.06p/kWh). This is an arbitrary price set
more than two decades ago and is not based on
actual experience – no fuel disposal facilities exist
in the United States or anywhere else – and all the
US spent fuel remains in temporary storage pending the construction of a spent-fuel repository,
expected to be at Yucca Mountain. Real disposal
costs are likely to be much higher.

Table 7 – Price of uranium
Uranium
10 Years (Mar 11, 2000 – Mar 10, 2010)
160
140

Uranium (USD/lb)

120
100
80
60
40
20
0
Mar 11
2000

Nov 1
2001

Jun 242003

Feb 13
2005

Oct 6
2006

May 282008

Jan 182008

Source: http://www.infomine.com/investment/charts.aspx?mv=1&f=f&r=10y&c=curanium.xusd.ulb#chart, 2010-03-11

26

The Economics of Nuclear Power: An Update

The issue of spent-fuel disposal is difficult to reaching their original licensed lives of 40 years
evaluate. Reprocessing is expensive and, unless are being licensed by the US safety authorities
the plutonium produced can be profitably used, it for a further 20 years of operation. However, it
does nothing to help waste disposal. Reprocessing should not be assumed that there will be cheap
merely splits the spent fuel into different parts electricity once capital costs have been repaid.
and does not reduce the amount of radioactivity Life extension may require significant new
to be dealt with. Indeed, reprocessing creates a expenditures to replace worn-out equipment
large amount of low- and intermediate-level and to bring the plant in compliance with curwaste because all the equipment and material rent safety standards. Life extension is not always
used in reprocessing becomes radioactive waste. possible. For example, Britain’s AGRs, which
The previous contract between BNFL and British had a design life of 25 years, are now expected toEnergy (before its collapse) for reprocessing British run for 40 years, but life extension beyond that
Energy`s fuel was reported to be worth £300m per may not be possible because of problems withyear, which equates to about 0.5p/kWh. The new erosion and distortion of the graphite moderator
contract is expected to save British Energy about blocks.
£150-200 million per year, although this will be
2.7. Decommissioning and wastepossible only because of underwriting of losses at
BNFL by the government. Despite this poor cost disposal cost and provisions
experience, the United States was reported to be
These are difficult to estimate because there
considering allowing the reprocessing of spent
fuel, which has not occurred since a ban was is little experience with decommissioning commercial-scale plants andimposed by the Carterthe cost of disposal ofadministration. The cost
For a technology dominated by fixed
waste (especially intermeof disposing of high-levelcosts, it might be expected that doubling
diate or long-lived waste)
waste is hard to estimate
the life would significantly reduce fixedis uncertain (see Appendix
because no facilities havecosts per unit because there would be3). However, even schemes
been built or are even undermore time to recover these costs.
that provide a very high level
construction and any cost
In practice, this does not apply.
of assurance that funds will
projections must have a
be available when neededvery wide margin for error.
will not make a major difference to the overall eco2.6.	Accounting lifetime
nomics. For example, if the owner was required toplace the (discounted) sum forecast to be needed
One of the features of Generation III+ plants to carry out decommissioning at the start of theis that they are designed to have a life of about life of the plant, this would add only about 10%
60 years compared to their predecessors, which to the construction cost. The British Energy seggenerally had a design life of about half that. For a regated fund, which did not cover the first phasetechnology dominated by fixed costs, it might be of decommissioning, required contributions of
expected that doubling the life would significant- less than £20m per year, equating to a cost of only
ly reduce fixed costs per unit because there would about 0.03p/kWh.
be more time to recover these costs. In practice,
this does not apply. Commercial loans must be
The problems come if the cost has been inirepaid over no more than 15-20 years and in a dis- tially underestimated, the funds are lost, or thecounted cash flow calculation, costs and benefits company collapses before the plant completes its
more than 10-15 years forward have little weight expected lifetime. All of these problems have been(see Appendix 2).
experienced in Britain. The expected decommissioning cost has gone up several-fold in real terms
There is a trend of extending the life of exist- over the past couple of decades. In 1990, when theing plants. Some PWRs and BWRs that are now Central Electricity Generating Board (CEGB) was2. Key determinants of nuclear economics                                                                                                                               27privatised, the accounting provisions made fromcontributions by consumers were not passed
on to the successor company, Nuclear Electric.
The subsidy that applied from 1990 to 1996 –described by Michael Heseltine 20 as being to“decommission old, unsafe nuclear plants” – wasin fact spent as cash flow by the company owning
the plant, and the unspent portion has now beenabsorbed by the treasury. The collapse of British
Energy has meant that a significant proportionof their decommissioning costs will be paid by
future taxpayers.

2.8.	Insurance and liability
This is a controversial area because atpresent, the liability of plant owners is limited
by international treaty to only a small fraction of
the likely costs of a major nuclear accident. The
Vienna Treaty, passed in 1963 and amended
in 1997, limits a nuclear operator’s liability
to 300 million Special Drawing Rights or about$460 million (on Feb 22, 2009, US$1=0.653SDR 21).
At present the British government underwrites
residual risk beyond £140 million, though thelimit is expected to rise under the Paris andBrussels Conventions to €700 million (£500m).
The limit on liability was seen as essential toallow the development of nuclear power but canalso be seen as a large subsidy.

The German parliament’s Study Commission
on Sustainable Energy 2 2 compiled figures on theliability limits in OECD countries (see Table 8)
and this shows the wide range of liability limits
from very low sums, for example Mexico, to muchhigher sums, for example Germany.
The scale of the costs caused by, for example,
the Chernobyl disaster, which may be on the orderof hundreds of billions of pounds (it is invidiousto put a cost on the value of loss of life or incapacity but for insurance purposes it is necessary),means that conventional insurance cover would
probably not be available, and even if it was, its
cover might not be credible because a major accident would bankrupt the insurance companies.
There have been proposals that “catastrophebonds” might provide a way for plant owners toprovide credible cover against the financial costof accidents. A catastrophe bond is a high-yield,
insurance-backed bond containing a provision
causing interest and/or principal payments to bedelayed or lost in the event of losses due to a specified catastrophe, such as an earthquake. Whether
these would provide a viable way to provide someinsurance cover against nuclear accidents andwhat the impact on nuclear economics would be
will be hard to determine until concrete proposals
are made.

20	Michael Heseltine, President of the Board of Trade, Hansard, October 19, 1992.
21 The value of the Special Drawing Right is determined by a basket of the world’s four major currencies.
22 Deutscher Bundestag, Nachhaltige Energieversorgung unter den Bedingungen der Globalisierung und Liberalisierung,
Bericht der Enquete-Kommission, zur Sache 6/2002, chapter 3.3.2, table 3.3 (Berlin: Deutscher Bundestag, 2002),
p. 232, http://dip.bundestag.de/btd/14/094/1409400.pdf

28

The Economics of Nuclear Power: An Update

Table 8 – Liability limits for the OECD countries as of September 2001
Liability limits undernational legislation a

Belgium€298m   Finland€250m   France€92m   

Germany

unlimited   Great Britain€227m   Netherlands€340m   Spain

€150m   Switzerland

unlimited   

Slovakia€47m   

Czech Republic€177m   Hungary€143m   Canada€54m   

USA

€10,937m   

Mexico€12m   

Japan

unlimited   South Korea€4,293m   

Financial security requirements a, b€€2,500m c€€674m€€226m€€538mSource: Unofficial Statistics – OECD/NEA, Legal Affairs
Notes: a using official exchange rates June 2001-June 2002; b if different than the liability limit; c €256m insurance,€2.5bn operator’s pool, €179m from Brussels amendment to Paris Convention

3. Experience at Olkiluoto and Flamanville

These two plants are of particular importancebecause they are the only Generation III+ plants
for which there is any significant experience, albeit
for construction only, not operation.

3.1.	Olkiluoto
The Olkiluoto-3 order for Finland was seen
as particularly important for the nuclear industry
because it seemed to contradict the conventional wisdom that liberalisation and nuclear power
orders were incompatible. The Olkiluoto-3 reactor order of December 2003 was the first nuclear
order in Western Europe and North America sincethe 1993 Civaux-2 order in France and the firstorder outside the Pacific Rim for a Generation III/
III+ design. The Finnish electricity industry had
been attempting to obtain parliamentary approval for a fifth nuclear unit in Finland since 1992.
This was finally granted in 2002. The Olkiluoto-3
order was a huge boost for the nuclear industry

in general, and Areva NP in particular. Industry
anticipated that, once complete, the plant would
provide a demonstration and reference for otherprospective buyers of the EPR.
Finland is part of the Nordic electricity market
covering also Norway, Sweden, and Denmark. The
region is generally seen as the most competitiveelectricity market in the world. Finland also has agood reputation for the operation of the four units
located in the country. So there were high hopesthat this would answer many of the questions
concerning the “nuclear renaissance.” However,closer examination of the deal reveals some very
special features that show this deal is not representative of conditions in other markets.
The contract price for Olkiluoto-3 was reported
in 2004 to be €3 billion for a 1600 MW plant 23.
Subsequently, the price was reported to be €3.2
billion24 or €3.3 billion 25. Safety approval was given

23 Project Director Martin Landtman stated: “The value of the whole Olkiluoto 3 investment including the Turn-key
Contract is about EUR 3 billion in year 2003 money. No other figures are published”; personal communication,e-mail to Mycle Schneider, dated October 8, 2004.
24 Nucleonics Week, “EC Probing Claims Olkiluoto Loan Guarantees Were State Aid”, October 26, 2006.
25 Nucleonics Week, “Areva Reveals 47% Cost Overrun on Contract for Olkiluoto-3”, March 5, 2009, p. 1.

© Greenpeace / Nick Cobbing

3. Experience at olkiluoto and flamanville                                                                                                                                    29

30by the Finnish regulator, STUK, in March 2005 andsubstantive work on-site started in August 2005.
At the time the contract was signed, the value was
equivalent to about $3.6–4.0 billion (dependingon the contract price) or about $2,250–2,475/kW(€1=US$1.2). This cost included financing andtwo reactor cores and so the cost per kW in overnight terms would have been somewhat lower,
although given – as we can see below – the very
low rate of interest charged (2.6%), finance costs
would be low.
Although this cost was well above the nuclear
industry’s target of $1,000/kW of only a few years
before, it was still regarded by critics as a “loss-leader.”Areva NP had been trying to persuade either EDF or
one of the German utilities to place an order for an
EPR since the late 1990s 26 and there were fears
that if an order for the EPR was not placed soon,
AREVA NP would start to lose key staff 27 and thedesign would become obsolete 28. AREVA NP alsoneeded a “shop window” for EPR technology andOlkiluoto-3 would serve as a reference plant forother orders. As an additional incentive and at
the request of the customer, AREVA NP offered
the plant on “turnkey” or fixed price terms. It also
took responsibility for the management of the site
and for the architectural engineering, not just the
supply of the “nuclear island.” This was not a role
it was accustomed to. For the 58 PWRs, Areva NP’s
predecessor, Framatome, had supplied for France,
as well as for the foreign projects including thosein China and South Africa; it was EDF that hadprovided these services.
As has been documented elsewhere 29, theOlkiluoto project has gone seriously wrong since

The Economics of Nuclear Power: An Update

construction started. By March 2009 30 the project
was acknowledged to be at least three years lateand €1.7 billion over budget 31. In August 2009,
Areva NP acknowledged that the estimated cost
had reached €5.3 billion, which at the prevailingexchange rate of €1=US$1.35 represented a costof $4,500/kW 32. The contract is also the subject ofan acrimonious dispute between Areva NP and
the customer, Teollisuuden Voima Oy. Areva NP
is claiming compensation of about €1 billion
for alleged failures of TVO. TVO, in a January
2009 counterclaim, is demanding €2.4 billion incompensation from Areva NP for delays in the
project 33.
It seems unlikely that all the problems thathave contributed to the delays and cost-overruns have been solved; the final cost could besignificantly higher. The result of the claim andcounter-claim arbitration between Areva NP
and TVO will determine how the cost-overrun
will be apportioned. Regardless, however, it isclear that investor concerns on plant costs anddelivery remain valid.

3.2. Flamanville
EDF finally ordered an EPR reactor in
January 2007, to be located at their Flamanvillesite. This reactor was uprated to 1630 MW 34 andconstruction commenced in December 2007 35.
In May 2006, EDF estimated the cost would be€3.3 billion 36. At that time (€1=US$1.28), this was
equivalent to $2,590/kW. This cost, however, did
not include the first fuel, so the overnight cost
would have been somewhat higher. The costestimate did not include financing either.

26 Nucleonics Week, “Giant EPR Said To Be Competitive: EDF To Decide on Order Next Year”, November 6, 1998, p.1.
27 Petroleum Economist, “France Mulls Nuclear Future”, March 2001.
28 Nucleonics Week, “EPR Safety Approval Won’t Last Beyond 2002, Regulator Warns”, March 6, 1997.
29 S. Thomas, “Can Nuclear Power Plants Be Built in Britain without Public Subsidies and Guarantees?”, Presentation ata conference, Commercial Nuclear Energy in an Unstable, Carbon Constrained World, co-hosted by the Nonproliferation
Policy Education Center and Radio Free Europe/Radio Liberty, March 17-18, 2008, Prague, Czech Republic.
30 Nucleonics Week, “Areva’s Olkiluoto-3 Manager Says Engineering Judgment Undermined”, March 26, 2009, p. 4.
31 Nucleonics Week, “Areva Reveals 47% Cost Overrun”.
32 Nucleonics Week, “With Expected Losses Mounting, Areva Seeks Changes in Ol3 Project”, September 3, 2009.
33 Agence France Presse, “Setbacks Plague Finland’s French-built Reactor”, January 30, 2009.
34 Nucleonics Week, “EDF Orders Flamanville-3 EPR NSSS, with Startup Targeted in 2012”, January 5, 2007, p. 1.
35 Nucleonics Week, “Flamanville-3 Concrete Pour Marks Start of Nuclear Construction”, December 6, 2007, p. 3.
36 Nucleonics Week, “EDF to Build Flamanville-3, Says First EPR Competitive with CCGT”, May 11, 2006, p. 1.

3. Experience at olkiluoto and flamanville                                                                                                                                    31EDF did not seek a turnkey contract thatcarried out the architectural engineering andmanaged the contracting – for example letting
contracts – for the turbine generator. How far
these decisions were influenced by the poor
experience at Olkiluoto and how far they were
influenced by the need it saw to maintainin-house skills is not clear.
In May 2008, the French safety regulatory
authorities temporarily halted construction at
Flamanville because of quality issues in pouring the concrete base mat 37. Delays had led thevendor, Areva NP, to forecast the plant would
not be completed until 2013, a year late. But inNovember 2008, EDF claimed the delays could
be made up and the plant finished to the originalschedule of 2012 38. EDF did acknowledge that the
expected construction costs for Flamanville had
increased from €3.3 billion to €4 billion 39. This
was then equivalent (€1=US$1.33) to $3,265/kW,
substantially more than the Olkiluoto contract
price, but far below the levels being quoted in
the United States and the actual cost of Olkiluoto.
There have also been claims by the trade unions
involved that construction at Flamanville is running at least two years late 40. An Areva official
has suggested that the cost of an EPR will now beat least €4.5 billion, although it was not specified
whether this was an overnight cost 41.

37 Nucleonics Week, “Concrete Pouring at Flamanville-3 Stopped after New Problems Found”, May 29, 2008, p. 18.
38 Nucleonics Week, “EDF Confirms Target of Starting Up Flamanville-3 in 2012”, November 20, 2008, p. 1.
39 Associated Press Worldstream, “EDF To Lead up to Euro50b in Nuclear Plant Investment”, December 4, 2008.
40 Nucleonics Week, “French Union: Flamanville-3 Delayed”, January 28, 2010, p. 1.
41 Nucleonics Week, “Areva Official Says Costs for New EPR Rising, Exceeding $6.5 billion”, September 4, 2008, p. 1.

The Economics of Nuclear Power: An Update

Colin Grey

32

4. The US programme

The Bush administration made a concerted
effort to revive nuclear ordering under its Nuclear
Power 2010 programme, announced in February
2002. The programme focuses on Generation III+
designs. When it was announced, it was expectedthat at least one Generation III+ unit and one
reactor of a more advanced design would be inoperation by 2010. Under the programme, the US
Department of Energy expected to launch cooperative projects with industry:[…] to obtain NRC approval of three sites
for construction of new nuclear power plants
under the Early Site Permit (ESP) process, andto develop application preparation guidance
for the combined Construction and Operating
License and to resolve generic COL regulatory
issues. The COL process is a “one-step” licensing
process by which nuclear plant public healthand safety concerns are resolved prior to commencement of construction, and NRC approves
and issues a license to build and operate a new
nuclear power plant 42.

In addition:[…] to complete the first-of-a-kind Generation
III+ reactor technology development and todemonstrate the untested Federal regulatory
and licensing processes for the siting, construction, and operation of new nuclear plants 43.
The rationale for the Nuclear Power 2010
programme was that the new nuclear designs
would be economically competitive. However,bad experience with building nuclear plants in
the United States in the 1980s and 1990s meantthat utilities would be reluctant to order nuclear plants until it had been fully demonstrated
that the new designs and procedures resolved
the issues that had led to these problems. The
policy to overcome these barriers was therefore
to streamline regulatory processes, ensure regulatory approval for a number of new designs,
and provide subsidies initially for three projects(perhaps six units), after which ordering would
require no subsidies.

42 http://www.ne.doe.gov/NucPwr2010/NucPwr2010.html
43 United States Department of Energy (DoE), A Roadmap to Deploy New Nuclear Power Plants in the United States by
2010 (Washington, DC: USDOE, 2001).

4. The us programme                                                                                                                                     33A total of up to $450 million in grants was initially proposed for at least three projects. Threemain organisations emerged to take advantageof these subsidies, with two signing agreementswith the USDOE to develop COLs. Nustart,
launched in 2004, was made up of a consortium of eight US utilities, including Entergy,
Constellation Energy, Duke Power, Exelon,
Florida Power & Light, Progress Energy, Southern
Company and the Tennessee Valley Authority(TVA, providing staff time not cash). The Frenchutility, EDF, and the vendors Westinghouse andGE were also members but had no voting rights.
Nustart planned to make two applications, one
for a GE ESBWR at Entergy’s Grand Gulf (Texas)
site and one for a Westinghouse AP1000 at TVA’s
Bellefonte site. The other main group is led by
the utility Dominion. Dominion was seeking a
COL for an advanced version of Atomic Energyof Canada’s Candu design, the ACR-700, at North
Anna (Virginia), where Dominion operates
two reactors. However, in January 2005, it announced that it had replaced the ACR-700 with
GE’s ESBWR because of the expected time for a
Candu plant to be licensed in the United States.
A Candu design has not achieved regulatory approval in the United States and the NRC forecast
that its approval process could take more than
60 months – much longer than it then expected
would be required for a Generation III+ PWR or
BWR. Subsequently, it has become clear that all
the new designs being assessed by the NRC willtake more than 60 months to assess.
Since the Energy Policy Act of 2005 (EPACT),
the timescale of the programme has slipped but
the scope has expanded to accommodate thelarge number of US utilities expressing an interest in building plants, and the scale of support
on offer has also increased dramatically. By thestart of 2009, plans to build 31 units had beenannounced (see Table 9).

A package of subsidies was later proposed
for this handful of demonstration units, of which
two have turned out to be the most important:production Tax Credits: In order to makeelectricity generated from new nuclear power
plants competitive with other sources of energy,
an $18/MWh tax credit would be paid for the firsteight years of operation. According to the Energy
Information Administration (EIA), this subsidy
would cost US taxpayers $5.7 billion by 2025 44;
loan Guarantees: To ease the difficultyof financing new plants, loan guarantees were
offered so that utilities could borrow at government
treasury bond rates. The Congressional Budget
Office concluded that the risk for loan default by
the industry would be “well above 50%” 45. The
Congressional Research Service estimated that the
taxpayer liability for loan guarantees covering up
to 50% of the cost of building six to eight new reactors would be $14-16 billion 46.
EPACT offered up to $500 million in risk insurance for units 1-2 and $250 million for units 3-6.
This insurance would be paid if delays not attributable to the licencee slowed licensing of the plant.
It also offered support for R&D funding worth$850 million and help with historic decommissioning costs worth $1.3 billion.
It soon became clear that the loan guarantees
were not only the key element of the package,
but that the extent of coverage offered was insufficient to allow utilities to place orders. Federal
loan guarantees were originally expected to cover up to 80% of the debt involved in the projectand if debt accounted for about 60% of the costof building the plant (the rest from equity), thiswould mean about half the cost of the plant
would be covered. Utilities successfully lobbied
for 100% coverage of debt up to 80% of the projectcost. Banks were also vocal in their call for full

44 United States Department of Energy (DoE), Analysis of Five Selected Tax Provisions of the Conference Energy Bill of
2003 (Washington, DC: Energy Information Administration, 2004), p. 3,
http://tonto.eia.doe.gov/FTPROOT/service/sroiaf(2004)01.pdf
45 Congressional Budget Office, Cost estimate of S.14, Energy Policy Act of 2003 (Washington, DC: Congressional
Budget Office, May 7, 2003), http://www.cbo.gov/doc.cfm?index=4206
46 Congressional Research Service (CRS), Potential Cost of Nuclear Power Plant Subsidies in S.14 (May 7, 2003);
requested by Senator Ron Wyden.

34

The Economics of Nuclear Power: An Update

Table 9 – US nuclear projects announced under “Nuclear Power 2010”
Plant

Owner

NRC Status

Loan
guarantee

DesignExpected
on-lineCalvert Cliffs 3

Unistar

COL application
submitted 3/08

Short-listed

EPR?

South Texas 3,4

NRG

COL application
submitted 9/07

Short-listed

ABWR

?

Bellefonte 3,4

TVA

COL application
submitted 10/07

Not eligible

AP1000?

Calvert Cliffs 3

Unistar

COL application
submitted 3/08

Short-listed

EPR?

South Texas 3,4

NRG

COL application
submitted 9/07

Short-listed

ABWR

?

Bellefonte 3,4

TVA

COL application
submitted 10/07

Not eligible

AP1000?

North Anna 3

Dominion

COL application
submitted 11/07

Applied

ESBWR?

Lee 1,2Duke

COL application
submitted 12/07

AppliedAP10002021-23

Harris 2,3

Progress

COL application
submitted 2/08

Not applied

AP10002019-20

Grand Gulf 3Entergy

COL application
submitted 2/08

Applied

ESBWR

Suspended

Vogtle 3,4Southern

COL application
submitted 3/08

Short-listed

AP10002016

Summer 2,3

SCANA

COL application
submitted 3/08

Short-listed

AP10002016-19

Callaway 2

AmerenUE

COL application
submitted 7/08

AppliedEPR

Suspended

Levy 1,2

Progress

COL application
submitted 7/08

AppliedAP10002019-20

Victoria 1,2

ExelonCOL application
submitted 9/08

Applied

ESBWR

Suspended

DTE Energy

COL application
submitted 9/08

Not applied

ESBWR

?

Comanche Peak 3,4

TXU

COL application
submitted 9/08

First reserve

APWR

?

Nine Mile Point 3

Unistar

COL application
submitted 10/08

AppliedEPR

Suspended

Bell BendPPL

COL application
submitted 10/08

AppliedEPR

2018

Amarillo 1,2

Amarillo

?

EPR

?

Fermi 3

4. The us programme                                                                                                                                     35OwnerNRC Status

Loan
guarantee

DesignExpected
on-lineRiver Bend

Entergy

COL application
submitted 9/08

Applied

ESBWR

Suspended

ElmoreUnistar?

EPR

Suspended

Turkey Point 6,7

FPL

COL application
planned 3/09

AP10002018–20

Plant?

Source: Various press reports
Note: More details on the individual projects are available in Appendix 4

coverage. A statement in 2007 signed by six ofWall Street’s largest investment banks (Citigroup,
Credit Suisse, Goldman Sachs, Lehman Brothers,
Merrill Lynch, and Morgan Stanley) informed the
USDOE that they were unwilling to extend loans
for new nuclear power plants unless taxpayers
shouldered 100% of the risks 47.

AP1000; GE-Hitachi ESBWR; GE-Hitachi ABWR 48;
Areva NP EPR; and Mitsubishi APWR.
In 2002, when the programme was launched,
construction costs of $1,000/kW were still expected, and the guarantees needed for six units ofabout 1400 MW, each covering 50% of the total
cost, would have been about $4.2 billion. But in
2008, if we assume 15 units will be eligible andwill be covered up to 80% of their total cost of$6,000/kW, guarantees worth in excess of $100
billion would be required.

In states where the electricity market is lessliberalised and utilities operating under regulated tariffs with a regulated asset base, loan
guarantees may be less vital. If regulators agree,
as some have, in advanceof completion of the plant
The Energy Bill passed
A statement in 2007 signed by six of
to allow the utility to begin
in 2007 gave the USDOE
Wall Street’s largest investment banks
to recover the construca budget of up to $18.5
informed the USDOE that they weretion cost of the plant, there
billion for 2008/09 forunwilling to extend loans for new
will be a significant shiftloan guarantees covering
nuclear power plants unless taxpayers
in the construction risks
nuclear plants. The USDOE
shouldered 100% of the risks.
away from the utility toshort-listed five projects
the consumers. This may
for these loan guarantees
mean financiers will offer loans at a much lower in February 2009. These were Southern Company
rate than if the plant had to compete in a market.
(Vogtle), South Carolina Electric & Gas (Summer),
Unistar Nuclear Energy (Calvert Cliffs), NRG
The scope of the subsidies also grew, going (South Texas), and the Comanche Peak project.
from covering just three sites (up to six units) The list was subsequently reduced to four projects
to loan guarantees for up to three units of each when the Comanche Peak project was relegated“innovative” design, and by 2008, five qualifying to first reserve in May 2009. Appendix 4 gives a“innovative designs” were being processed by detailed description of the status of the announced
the Nuclear Regulatory Commission (NRC). This nuclear projects in the United States.
meant up to 15 units would be eligible for loan
guarantees. The five designs are: Westinghouse
47 Investors’ comments in response to DOE notice of proposed rulemaking, July 2, 2007.
48 Toshiba may also offer the ABWR independently from GE-Hitachi.

36

The Economics of Nuclear Power: An Update

4.1.	Likely outcomes
While reactor designs are being reviewed by
the NRC, all raise significant questions. The APWR
has been close to commercial order in Japan forabout a decade, but for reasons that are not clear,
the order has not materialised. In the UnitedStates, it has only one customer, and if that project
should not proceed and the Japanese order continues to be delayed, the technology would seemto have little future.
There is little interest in the ESBWR outside theUnited States, and since 2008 it has lost three outof five of its US customers. These customers havemade damaging comments about the uncertainty
of construction costs and how close to commer­
ciality the design is. The remaining two customers
for the ESBWR (Dominion and DTE Energy) are
not on the short-list for loan guarantees. If theseorders fall through, it will be hard for the ESBWR
to survive; if they do not, this would raise questions about GE’s future as a reactor vendor.
The ABWR has only one customer (NRG), andthat project experienced serious difficulties in late2009 because of escalating costs. It has the strong
advantage of being a demonstrated technologythat already has regulatory approval from the NRC.
However, this approval runs out in 2012 and any
new orders would have to await renewal of its certification. The NRC has yet to give any indicationof the extent of any changes that would need to be
implemented, for example, on aircraft protection.
The ABWR’s advantage as a proven technology will
disappear if the list is extensive and the process toreview the design-changes is lengthy.
The image of the EPR is being seriously
damaged by the problems at Olkiluoto (andFlamanville) and by the difficulty of resolving
the control and instrumentation issue with theEuropean safety regulators. Three out of six ofits projects appear to be dormant and only the
Calvert Cliffs project is well-advanced.
The AP1000 appears to be in the strongest position. It accounts for nearly half of the announced
reactor units (14 out of 31) and two out of fourof the projects shortlisted for loan guarantees,
including the project most likely to get the first ofthese, Vogtle. None of the AP1000 projects appear
to have been abandoned yet, although the TVA
Bellefonte project is now in some doubt. It has
already received NRC design approval (in 2006)
although Westinghouse/Toshiba has subsequently submitted design revisions for which review
will not be complete before 2011. Westinghouse/
Toshiba is experiencing some difficulty resolving
safety issues concerning the end-shield on bothsides of the Atlantic. In February 2010, the UK
nuclear safety regulator raised a “regulatory issue”
on this design aspect 49.
The existing loan guarantees committed by
the US government until the end of 2009 – $18.5
billion – would probably have been consumedby just two projects. There is also the problem of
establishing what fee the utilities should have to
pay to receive these guarantees. Given that loan
guarantees are effectively an insurance policy, the“premium” should reflect the risk of default. The
Congressional Budget Office has estimated that the
net default risk would be 25% (50% but half of thecost would be recovered by selling off equipment).
It seems highly improbable that utilities borrowing– say, $10 billion for a two unit project – would be
prepared to pay a fee of $2.5 billion just to receive
loan guarantees. The utilities are asking for a feeof 1% 50, but this seems unlikely to be politically
acceptable.
In February 2010, in its 2011 budget, the Obamaadministration approved an increase in the amountavailable for loan guarantees, from $18.5 billion
to $54.5 billion (perhaps enough for 12 units) 51.

49 If the regulatory issue is not resolved within a specified time limit (in this case), the safety authorities may refuse togive the design generic design approval see http://news.hse.gov.uk/2010/02/16/                                                 hse-raise-regulatory-issue-ri-against-westinghouses-ap1000-nuclear-reactor-design/
50 Electric Utility Week, “Change to DOE Guarantee Programme Boosts Nuclear Hopefuls; Size of Fee Remains an
Issue”, December 14, 2009.
51 Associate Press, “A Look at Obama’s 2011 Budget for Gov’t Agencies”, February 1, 2010.

4. The us programme                                                                                                                                     37In February 2010, the USDOE announced thatloan guarantees worth $8.33 billion had been allocated to the Vogtle (Georgia) project for two AP1000
units 52. The loan guarantees were expected to cover
7% of the costs (at least for the main owner, Georgia
Power) although the details of the fee that would
be charged for the loan guarantee was not specified. The forecast cost of the plant is therefore about$11.9 billion, or $5,000/kW. The Georgia PublicService Commission had already accepted Georgia
Power’s request to be allowed to start recovering theconstruction cost from its monopoly consumers(see Appendix 4). So any bank lending money to theproject had double protection: from the federal government (taxpayers) via loan guarantees; and fromconsumers via guaranteed cost-recovery.
This model of double protection does showthat nuclear plants can be built if the governmentis prepared to provide large enough subsidies.
However, it does not seem likely to be sustainable
for more than a few demonstration units, especially if the project does not go smoothly and taxpayers
and consumers are forced to meet extra costs.

52 Washington Post, “Obama To Help Fund Nuclear Reactors”, February 17, 2010.

The Economics of Nuclear Power: An Update

Redjar38

5. The UK programme

The UK government’s programme is based onvery different underlying assumptions than that of
the United States. The UK government has neverclaimed that nuclear power would be directlycompetitive with fossil fuels, but if a carbon priceof €36/ton was assumed, it would be competitive. Ordering would therefore take place without
subsidy, provided a few non-financial enabling
decisions were taken, particularly on planning
processes and certification of designs. In 2008,
when the government revisited nuclear economics, it assumed the construction cost was £1,250/
kW ($2,000/kW), representing a real increase incosts of about 20% over the 2002 figures 53.
The government’s nuclear regulator, theNuclear Installations Inspectorate (NII), started
to examine four separate designs in 2007: theWestinghouse/Toshiba AP1000; the Areva NP EPR;
the GE-Hitachi ESBWR; and a Canadian heavywater reactor design, the ACR-1000 (Advanced
CANDU Reactor). The rationale was that up to
three designs would be finally certificated, thus

giving utilities a choice of designs. Most observers expected that the EPR and AP1000 would be
the final choices, and so it has proved. The ACR1000 was quickly withdrawn and in late 2008, the
ESBWR was also withdrawn.
The NII has experienced severe difficulties
recruiting sufficient inspectors to carry out
its tasks, and in November 2008, it was still 40
inspectors (about 20%) short of the required
number. By July 2009, the shortage was 54
inspectors (24%) 54. Some of the utilities operating in the United Kingdom, especially EDF,
have said they expect to be able to order plants
without subsidies.
However, realistically, orders cannot be placed
for at least five years in order to allow regulatory
approval for the chosen design and planningapproval for a site. Three utilities have made significant commitments to UK ordering: EDF, RWE,
and E.ON – the latter two in consortium. EDF
took over the UK nuclear generation company,

53 Department for Business, Enterprise and Regulatory Reform, “Meeting the Energy Challenge: A White Paper on
Nuclear Power”, Cm 7296, HMSO, London, p. 61, http://www.berr.gov.uk/files/file43006.pdf
54 Inside NRC, “UK’s NII Short on Inspectors, Sees Years of Recruitment Struggle”, July 20, 2009, p. 9.

5. The uk programme                                                                                                                                    39British Energy, for about €15 billion in 2008, while
RWE/E.ON have purchased sites in 2009 adjacent
to existing nuclear power plants for several hundred million euros. Both EDF and the RWE/E.ON
consortium expect to order 4 units, for a total of
10 to 12 GW of capacity. EDF is expected to orderthe EPR, while the RWE/E.ON consortium has yet
to choose its supplier.

5.1.	Likely outcomes
While the 2009 UK government was heavily
committed to reviving nuclear ordering in the
United Kingdom, there can be no guarantee thatwhen it comes to place orders, the commitmentof the government of the day will be so strong.
EDF had also heavily committed itself to nuclear
ordering in the United Kingdom with its purchasein 2009 of British Energy for about €15 billion.
This price seems far above the value of the assets
being acquired and only has any logic if new
nuclear orders are placed.
British Energy went bankrupt in 2002 because
its operating costs, then about £16/MWh, were
marginally higher than the price it received
for electricity. Since then, operating costs havegrown every year and by 2008/09, the operating
costs had risen to £41.3/MWh. British Energy only
remained solvent because of the extremely highwholesale electricity prices that prevailed in that
period – British Energy received £47/MWh in that
period. If operating costs continue to rise and/or wholesale electricity prices fall (by the endof 2009, they were well below the 2008 peak),
British Energy will be at risk of collapse again.
In theory, EDF could simply abandon British
Energy (the company was acquired via a whollyowned subsidiary, Lake Acquisitions) but thiswould be unlikely to be politically acceptable.
The RWE/E.ON consortium had invested a few
hundred million pounds in options to buy sites,
but if it did not take up these options, it could
walk away from a British nuclear programme atlittle cost.

By the start of 2010, the UK was still 3 to 4
years away from completing safety assessmentsof the designs and getting planning permission
for specific sites – the point when a firm ordercould be placed. At that point, other options,such as renewables and energy efficiency, will
most likely not be developed enough to bebrought in, and the United Kingdom will be ina position of having to order nuclear plants tokeep the lights on. The government will thenhave to accede to whatever demands the utilities make.
The first major chink in the government’s “nosubsidies” policy came in February 2010, when the
Energy Minister, Ed Miliband, told the Times 55:“The Neta system [the British wholesalemarket], in which electricity is traded via contracts between buyers and sellers or power
exchanges, does not give sufficient guarantees
to developers of wind turbines and nuclear
plants.”He said that one alternative would be a returnto “capacity payments” – in which power station
operators would be paid for the electricity theygenerate and also for capacity made available. The
idea of such payments is to give greater certainty
to investors in renewable and nuclear energy.
A day later, the national economic energy regulator announced 56:
The unprecedented combination of the
global financial crisis, tough environmental targets, increasing gas import dependency and theclosure of ageing power stations has combined
to cast reasonable doubt over whether the current energy arrangements will deliver secureand sustainable energy supplies […]. There is anincreasing consensus that leaving the present
system of market arrangements and other incentives unchanged is not an option.
If the result of these two statements is that
nuclear power plants will get large “capacity pay-

55 The Times, “Labour Prepares To Tear Up 12 Years of Energy Policy”, February 1, 2010.
56 Ofgem, “Action Needed To Ensure Britain’s Energy Supplies Remain Secure”, press release R5, February 2010,
http://www.ofgem.gov.uk/Media/PressRel/Documents1/Ofgem%20-%20Discovery%20phase%20II% 20Draft%20v15.pdf

40

ments” whether or not they operate and thewholesale market is abandoned in favor of amuch more planned (less economically risky)system, the income for a nuclear power plant

The Economics of Nuclear Power: An Update

operator could be sufficiently guaranteed (byconsumers) so that the economic risks of nuclear power could be reduced sufficiently so as toallow for cheap financing.

Trey Ratcliff

6. Germany                                                                                                                                     416. Germany

Germany operates 17 power reactors. In 2002
the parliament passed a nuclear phase-out law
that requires they be shut down after an average
lifetime of about 32 years. However, the utilities
had a total “nuclear electricity-generating budget”
of 2,623 billion kWh (corresponding to the annual
world nuclear power production) and can transfer
remaining kWh from one reactor to another unit.
Two units have already been shut down under thephase-out law (Stade, Obrigheim). A third unit
(Mülheim-Kärlich) that had been under long-term
shutdown since 1988 has been closed for good. The
construction of new nuclear plants and spent-fuelreprocessing (beyond quantities of fuel shipped toreprocessing plants until June 30, 2005) is prohibited.
Some expected the election of the new Merkel
government in September 2009 to lead to a rever­sal of the phase-out policy and perhaps even neworders. However, the new coalition government led
by the Christian Democrats (CDU) with the Free
Democrats (FDP) and the Christian Social Union(CSU) has been cautious in changing the law. The
government has signaled it might extend the life of

the existing plants but it has agreed not to remove
the phase-out policy  57. For fall 2010, the government
has promised a national review of energy policythat will take a comprehensive look at the situationand propose the government’s strategy, including
the issue of reversing the phase-out policy.
While it is clear that the two major utilities,
RWE and E.ON, would like to build new nuclear
plants, their first priority will be to maintain their
existing plants in operation. Two, Neckarwestheim
1 and Biblis A, will be closed in 2010 unless thegovernment acts. If the life of the existing plants
is extended, their initial capital costs will havebeen repaid and – provided major repairs andupgrades are not needed – these plants will produce very cheap power. One German economist,
Wolfgang Pfaffenberger, estimated that these
additional profits could amount to €200 billion,
if the life of the existing 17 reactors was extended to 60 years 58. Until now the government has
struggled to answer how it can legally justify the“use” of these windfall profits if it allows operators to keep their plants running longer.

57 Nucleonics Week, “New German Government Will Postpone Nuclear Policy Decisions until Late 2010”, November 5, 2009.
58 Nucleonics Week, “Tax Revenue from Longer Lifetimes No Incentive for New German Regime”, December 4, 2009.

42

Simone Ramella

The Economics of Nuclear Power: An Update

7. Other markets

While many countries have expressed an interest in new nuclear power plants, the time from“expression of interest” to the actual order is a very
long one and one in which there is ample scopefor failure. In this section, we therefore concentrate on markets that are of symbolic importance,
especially Italy; ones where calls for tender havealready taken place, for example, South Africa andCanada; and countries where efforts to restart
work on partially built plants are underway.

7.1.	United Arab Emirates
In December 2009, the United Arab Emirates
ordered four nuclear reactors from South Korea
using AP1400 technology, beating opposition fromconsortia led by EDF (including GDF Suez, Areva,
Total with the EPR) and GE-Hitachi (technology
unspecified) 59. The contract is with Korea Electric
to build and operate the plants, the first coming
on-line at an unspecified site in 2017 and the lastby 2020. KEPCO will provide design, construction,and maintenance for the nuclear reactor and will

subcontract some of the work to equipment suppliers such as Hyundai, Doosan, and Samsung.
The terms of the deal and what is included are notclear, although the contract is reported to be worth$20.4 billion. The South Korean bid was reported
to be $16 billion lower than the French bid, and
the GE-Hitachi bid was reported to be significantly
higher 60. It appears not to be a whole project “turnkey” (fixed price) deal. South Korean companies
will hold an equity stake in a joint venture with
UAE public companies, which will operate theplants after their completion 61. It is not clear how
the plants will be financed.
There seems to be ample scope for things to go
wrong with this project:
the technology is untested: there is only
about a year of construction experience with thisdesign;there is little nuclear expertise in the region;
the timescale will be very difficult to meet
and the contract price appears to be about 40%

59 Korea Herald, “Korea Wins Landmark Nuclear Deal,” December 28, 2009.
60 Right Vision News, “UAE: Middle East Leads Rally in Nuclear Plant Orders”, January 12, 2010.
61 International Oil Daily, “South Korean Consortium Awarded UAE Nuclear Contract”, December 29, 2009.

7. Other markets                                                                                                                                    43lower than the cost estimates for plants planned byexperienced US utilities;
the South Korean nuclear industry has noexperience with supplying reactors outside South
Korea;
there is little of the infrastructure needed
to operate a nuclear power plant in the UAE – forexample a safety regulator was only set up in late2008.

of the previous year for 3200 to 3400 MW of new
nuclear capacity in the near term and up to 20,000
MW by 2025. One bid was from Areva for two EPRs
(plus 10 more for the long-term) and the otherfrom Westinghouse for the three AP1000s (plus 17
more in the long term) 64. Both claimed their bids
were “turnkey”, but whether they were really turnkey in the fixed price sense or whether they were
simply for the whole plant is not clear.

7.2.	South Africa

It was later reported that the bids were foraround $6,000/kW – more than double the expectSouth Africa was pinning its hopes for its ed price 65. It was therefore no surprise when Eskom
nuclear programme on the Pebble Bed Modular abandoned the tender in December 2008 on theReactor (PBMR) from 1998 onwards. However, grounds that the magnitude of the investment wasby 2006 it was clear that the PBMR would at too much for it to handle 66. This was despite thewillingness of Coface, thebest be long-delayed, andFrench government’s loan
at worst not viable. The
While many countries have expressed
guarantee body, to offer
PBMR is now unlikely to be
an interest in new nuclear power
export credit guarantees
deployed even as a demplants, the time from “expression ofand despite Areva’s claims
onstration plant before
interest” to the actual order is a very
that it could have arranged
2020 and the South African
long one and one in which there is
85% of the financing 67. In
state-owned utility, Eskom,
ample scope for failure.
February 2009, Eskom also
is not expecting to orderabandoned plans to build
any units of this design.
PBMRs 68. While Eskom is still claiming it expects
The South African government and Eskom to order nuclear plants, it seems unlikely that it willthen began to talk about a programme of what be able to finance these.
they termed conventional nuclear power plants.
Engineering News reported that the issue was
As with the PBMR, their estimates for duration andcosts were hopelessly unrealistic. In 2006 62, the the credit rating of Eskom 69:
South African government forecast that a new unit
In fact, ratings agency Standard & Poor’s
could be on-line between 2010 and 2012.
said on Thursday that South Africa’s National
Treasury needed to extend “unconditional, timeBy mid-2007, Eskom was targeting construc- ly guarantees” across all Eskom’s debt stock if ittion of 20,000 MW on new nuclear capacity by hoped to sustain the utility’s current BBB+ invest2025, although completion of the first unit had ment-grade credit rating. The National Treasury
slipped to 2014 63. It expected a construction cost of was still to announce the details of the package.
$2,500/kW. In January 2008, Eskom received two The Eskom board had, as a result, decided to terbids in reply to its call for tenders from November minate the commercial procurement process to
62 Sunday Times (South Africa), “SA Going Nuclear”, June 24, 2006.
63 Nucleonics Week, “Cabinet Mulls Policy as Eskom Launches Consultation on New Plant”, June 7, 2007.
64 Nucleonics Week, “Eskom Gets Bids for Two EPRS, Three AP1000s, Bigger ‘Fleet’ ”. February 7, 2008.
65 Nucleonics Week, “Big Cost Hikes Make Vendors Wary of Releasing Reactor Cost Estimates”, September 11, 2008.
66 Nucleonics Week, “Eskom Cancels Tender for Initial Reactors”, December 11, 2008.
67 The Star, “Nuclear Bid Had Funding – AREVA”, January 30, 2009.
68 PBMR pty, “PBMR Considering Change in Product Strategy”, news release, February 5, 2009, 
http://www.pbmr.co.za/index.asp?Content=218&Article=104&Year=2009
69 Engineering News, “Eskom Terminates Nuclear 1 Procurement Process, but SA Still Committed to Nuclear”,
December 5, 2008.

44

The Economics of Nuclear Power: An Update

select the preferred bidder for the construction of
the Nuclear-1 project.
This history illustrates that loan guarantees are
not enough in themselves to guarantee nuclear
projects can be funded. If the credit rating of theutility is at risk, it will be hard to proceed.

7.3.	Canada

bid was C$23.6 billion (US$21 billion) for two
EPRs (1600 MW each) or C$7,375/kW (US$6,600/
kW), while AECL’s compliant bid was C$26 billion (US$23 billion) for two ACR-1000s (1200
MW each) or C$10,800/kW (US$9,600/kW). The
compliant bid was nearly four times the amountprojected by the OPA only two years previously.
The Westinghouse bid, the last of the three, wasreported to be about midway between the othertwo bids. Not surprisingly, Ontario decided tosuspend the tender.

In 2007, Ontario Power Authority (OPA), the public body responsible for planning the Ontario powersystem, had assumed nuclear power plants could
Subsequently, Areva disputed the published
be built for about C$2,900/kW 70. On June 16, 2008, bid price, but they were not willing to supply thethe Canadian government announced Darlington actual price they bid. There was also reported to be
in Ontario as the site for a two-unit new build a number of additional items included over andproject and on May 20, 2009, information leaked above those included in the “overnight price”, inthat the Ontario government had chosen AECL as cluding: the construction of the transmission andthe leading bidder over
distribution infrastructure
Areva and Westinghouse toto deliver the power fromThat loan guarantees are not enoughstart building the first new
the Darlington site to cusin themselves to guarantee nuclear
nuclear plants in Canada
tomers in the northeastern
projects can be funded. If the credit
in 25 years. Two new reacUnited States; and therating of the utility is at risk,
tors were projected toprice of nuclear fuel for 60
it will be hard to proceed.
start operating by 2018.
years and decommissionHowever, the provincial
ing costs 74.
government reportedly conditioned any go-ahead
The failure of AECL to be awarded this tenderon financial guarantees by the federal government to cover the financial risks involved 71. Three put its future as a reactor vendor in doubt andbids were received, including one from Areva AECL was put up for sale at the end of 2009 75.
and one from AECL, although only the AECL bid
7.4.	Turkey
complied with the requirement that the vendor
assume the construction risk. Ontario Energy andTurkey has been holding calls for tender for
Infrastructure Minister George Smitherman said
that only the AECL bid complied with the prov- nuclear power plants for about 30 years but has
ince’s requirement for vendors to bear the entire yet to place an order. In 2008, Turkey opened a callfor tenders for 3000 to 5000 MW of new nuclear
risk of cost-overruns 72.
capacity. Bidders would be required to cover not
There was a press report on the size of the just the construction cost but would be required tobids 73. This suggested that Areva’s non-compliant operate the plant for 15 years, offering the power
70 Toronto Star, “Nuclear Bid Rejected for 26 Billion: Ontario Ditched Plan for New Reactors over High Price Tag That Would
Wipe Out 20-Year Budget”, July 14, 2009.
71 The Globe and Mail, “AECL Favoured to Build Ontario Reactors: Sources”, May 20, 2009.
72 Nucleonics Week, “Areva Disputes EPR Cost Figure as Canadians Grapple with Risk Issue”, July 23, 2009.
73 Toronto Star, “Nuclear Bid Rejected”.
74 Nucleonics Week, “Areva Disputes EPR Cost”.
75 The Globe and Mail, “Canada Puts Its Nuclear Pride on the Block”: “Under weight of record deficit, Tories seek bids on
AECL’s reactor wing. The Candus are a point of pride in Canada's engineering history and the sale is sparking fears thetechnology will leave the country”, December 18, 2009.

7. Other markets                                                                                                                                    45at a fixed price 76. This was an extraordinary levelof risk to ask the vendors to cover. Despite reported interest from vendors such as GE-Hitachi,
Toshiba/Westinghouse, Korea Electric, andAreva, in January 2009 when bidding closed(it had to be extended), the only bid came fromthe Russian supplier, Atom Stroy Export (ASE).
The price bid was reported to be $211.6/MWh 77.
Subsequently, a revised bid of $151.6/MWh waspresented after TETAS, the state-owned electricity trader, submitted its report on the tender tothe government stating the bid was too high toproceed with 78. In November 2009, the Turkish
government scrapped the tender, which was,by then, under threat of being invalidated by acourt decision following action by the Turkish
Chamber of Engineers 79.

7.5.	Italy
In 1987, a referendum led to the closure of
the four operating nuclear power plants in Italy
and the abandonment of work on constructionof another nuclear station. The Berlusconi government has introduced legislation that would
pave the way for the reintroduction of nuclear
power in Italy. Four 1650 MW EPRs could bebuilt, with construction starting as early as 2013,
under an agreement signed in February 2009 by
the French utility, EDF, and the largest Italianutility, ENEL.
ENEL has not selected the sites for these units
yet. It has said the cost would be about €4 to 4.5
billion ($5.9 to 6.6) each or $3,600 to 4,000/kW 80.
There has been speculation about other competing bids to build nuclear power plants – forexample, a consortium led by A2A, the Milanbased utility offering AP1000s – but these projects
are much less advanced than those of ENEL 81.

7.6.	Brazil
Brazil operates two nuclear reactors, the firstof which, Angra-1, was ordered in 1970 from
Westinghouse. The reactor went critical in 1981. In
1975, Brazil signed with Germany what remains
probably the largest single contract in the history of the nuclear industry for the construction ofeight 1300 MW reactors over a 15-year period. The
outcome was a disaster. Due to an ever-increasing
debt burden and obvious interest in nuclear weapons by the Brazilian military, practically the entire
programme was abandoned. Only the first reactor
covered by the programme, Angra-2, was finallyconnected to the grid in July 2000 – 24 years after
construction started. The construction of Angra-3
was halted in June 1991. Attempts by the publicly
owned company, Eletronuclear, to get construction
restarted have been continually delayed. Work wasreported to have restarted in October 2009 withexpected completion in 2015 82. In January 2010,
Areva NP applied to the German government forloan guarantees worth €1.4 billion from the German
credit guarantee agency, Hermes, to complete
Angra-3 83.
Beyond this, the Brazilian government was
expecting, in late 2009, to announce the sites forfour new reactors. The Energy Minister, Edison
Lobao, has said each of the units is expected to cost
about $3 billion and generate up to 1500 MW. This
projected cost of $2,000/kW appears hopelessly
unrealistic and there must be strong doubts about
whether Brazil will proceed with nuclear orders in
the next five years.

7.7.	Eastern Europe
In this section we focus on efforts to restart
work on partially built plants, especially those in

76 Nucleonics Week, “GE-Hitachi Plans Bid To Build ABWR in Turkey; Other Vendors Cautious”, September 11, 2008.
77 Prime-Tass English-language Business Newswire, “DJ Atomstroyexport Grp Revises Bid in Turkish Nuclear Tender – IHA”,
January 19, 2009.
78 Turkey Today, “State-run TETAS Presents Report on Nuclear Power Tender to Energy Ministry”, June 30, 2009.
79 Agence France Presse, “Turkey Scraps Nuclear Power Plant Tender”, November 20, 2009.
80 Nucleonics Week, “Enel Targets 2020 for Operation of First Italian EPR Unit”, October 8, 2009.
81 Nucleonics Week, “Milan Utility A2A Could Become Hub of AP1000 Consortium for Italy”, October 22, 2009.
82 Esmerk Brazil News, “Brazil: Angra 3 Works Start”, October 13, 2009.
83 Taz, di tagezeitung, “Siemens will Staatshilfe für Atom-Export,” January 7, 2010.

46

The Economics of Nuclear Power: An Update

Bulgaria, Romania, and the Slovak Republic. New
reactors are being considered for the Baltic States,
Poland, and the Czech Republic, but these were
all some way from placing an order. In Bulgaria,
Romania, and the Slovak Republic, the projects tocomplete partially built units have been delayed by
up to a decade and their completion is still far fromcertain.

7.7.1. Slovak Republic
Mochovce was planned to host four Sovietdesigned reactors of the WWER-440 design. Workon this site was stopped in 1990 but work on twounits was later restarted and these were completed
in 1998 and 1999. In October 2004 the Italian utility
ENEL acquired 66% of Slovenske Elektrarne (SE).
As part of its bid, ENEL proposed to invest nearly€2 billion in new generating capacity, including
the completion of the third and fourth units of
Mochovce. In February 2007, SE announced that it
was proceeding with the completion of these units
and that ENEL had agreed to invest €1.8 billion.
Although the European Commission gave its permission for construction to restart in July 2008, it
noted that the reactor did not have a “full containment” structure, which is used in the most recent
construction of nuclear power plants plannedor under way in Europe, and they requested thatthe investor and national authorities implement
additional features to withstand impact fromsmall aircraft. Despite pressure from the Slovak
government, it took until June 2009 to reactivate
construction. The two units are now scheduled forcompletion in 2012 and 2013 respectively.

7.7.2. Romania
The Cernavoda nuclear power plant was
expected to house five “Candu” units whena contract was placed to build them in 1980.
Construction started in 1980 but later, all efforts
went to complete unit 1, which went on-line
in 1996. A second unit was completed in 2007
and plans are being developed to complete two

additional units. Bids have been solicited to create an independent power producer between theutility, SNN, which will complete and provide
operation and maintenance, and a private investor. Financing has proved difficult and delays
have continued. Initially, commissioning of unit 3
was due in October 2014 and unit 4 in mid-2015.
However, this has now been revised and the firstunit is not expected to be completed until 2016 at
the earliest 84.

7.7.3. Bulgaria
In 2003 the government announced its
intention to restart construction at the Belene site
in northern Bulgaria. Construction of a reactor
began in 1985, but following the political changes
in 1989 construction was suspended and formallystopped in 1992. In 2004 a call for tenders for thecompletion of the 2000 MW of nuclear capacity
was made. In October 2006 a consortium led by
the Russian company, Atom Stroy Export (ASE)
was awarded the €4 billion contract.
A Belene construction consortium has been
established in which the state utility, NEK, will retain
overall control, with 51%, with the remaining shares
having been put to tender. In late 2008 German utility RWE was announced as the strategic investor
with a requirement to put up €1.275 billion as wellas provide a €300 million loan in advance. This led
to the formation of the Belene Power Company inDecember 2008 as a joint venture. However, RWE
subsequently withdrew and at the end of 2009,
financing was still being arranged 85.

7.7.4. Other countries
In 2009, the Czech state-controlled utility,
CEZ, opened a call for tenders for two new reactors to be built at the Temelin site, where tworeactors already operate with an option to build
a third unit at another existing site, Dukovany 86.
The bidders are reported to be Westinghouse,
Atom Stroy Export, and Areva although the final

84 Nucleonics Week, “Economic Crisis Ends Romania’s Plan for Majority Stake in Cernavoda-3, -4”, September 3, 2009.
85 Balkans Business Digest, “Moscow in Talks with Sofia Over Stake in Belene Nuke”, December 28, 2009.
86 Czech Republic Today, “CEZ Admits All Bidders for Temelin Construction to Second Stage”, February 22, 2010.

7. Other markets                                                                                                                                    47decision is not expected before early 2012 withcompletion of the three units expected in 2019,2020, and 2023-25.
The Polish government has expressed its
intent to build new nuclear power plants but
the plans are at an early stage. The Lithuanian
government would like to replace the two Soviet-

designed nuclear reactors it has retired recently
but lacks the financing to do so. Unless a vendor
is prepared to organise a deal under which a partner of the vendor would own and operate theplant (as Korea Electric has done in the United
Arab Emirates), it seems unlikely a reactor order
will be possible.

© Greenpeace / Nick Cobbing

48

The Economics of Nuclear Power: An Update

8. Review of utility construction cost-estimates

Many of the recent utility cost-estimateshave come from the United States. These costestimates may be more reliable than other utility cost-estimates as the utilities will need toprovide reliable cost estimates to obtain loan

guarantees and may also need to account tostate energy regulators for the costs they expect
to incur. However, there have been indications of
the results of three calls for tenders and the experience from Olkiluoto and Flamanville to add.

8.1.	United States
Table 10 – Construction costs for US nuclear power plants
Plant

Technology

Cost estimate (US$bn)

Cost estimate US$/kW

Bellefonte 3, 4

AP1000

5.6-10.4*2,500-4,600

Lee 1, 2

AP100011*

4,900

Vogtle 3, 4

AP10009.9

4,190

Summer 2, 3

AP1000

11.5

4,900

Levy 1, 2

AP1000145,900Turkey Point 6, 7

AP100015-18

3,100-4,500

South Texas 3, 4

ABWR

17

6,500

Grand Gulf

ESBWR

10+

6,600+

River Bend

ESBWR

10+

6,600+

EPR

13-15

8,100-10,000

ESBWR

10

6,600+

Bell Bend
Fermi
Source: Various press reports

Estimates marked * are overnight costs; other estimates include interest

8. Review of utility construction cost-estimates

49

Table 10 shows the most recent construction
costs for US nuclear power plants. A number offactors emerge from this table. First, most of theestimates, especially the most fully worked out,
are for the AP1000 design. Because this and the
ABWR are the only designs that have completed
their NRC review process – albeit that both designs
are being revised again – it is easier to make construction cost-estimates because the design is closer toa final design. However, it is difficult to draw verystrong conclusions from this table, other than thatcost estimates appear to be at least four times the$1,000/kW figures that were being claimed by the
nuclear industry in the late 1990s and that cost estimates were continuing to rise at the end of 2009.
The basis for the figures varies: Some include
financing, some include transmission costs, andso direct comparisons are not reliable.

8.2.	Other countries
Table 11 summarises recent cost-evidence
from countries that have got at least as far as completing a call for tenders.

Table 11 – Recent nuclear power plant bids (US$/kW)
Country

Pre-bid
forecast

Lowest bid/
contract price

Most recent
estimate

StatusSouth Africa

2,500

6,000

-

Tender abandoned

Canada

2,600

6,600

-

Tender abandoned

UAE

-

3,700

-

Awaiting construction startFrance

-

2,700

3,300

Construction from 12/2008

2,500

4,500

Construction from 7/2005

Finland
Source: Author’s research

8.3.	Summary

rent cost estimates, while US plants completed in
the 1990s also cost about the same. It may be that
It is clear that in the past decade, the esti- plant designers assumed that starting without allmated construction cost for new nuclear plants the “baggage” that earlier generations of designs
has increased several-fold, perhaps more than had acquired in response to the safety challenges
five-fold, with no sign that the rate of increase is thrown up by Three Mile Island and Chernobyl,
leveling out. All past expenew designs could meetriences suggest that when
the safety requirements
In the past decade, the estimatedactual construction costs
but with much simpler
construction cost for new nuclear plants
are established, they will
designs, which would be
has increased several-fold, perhaps
be substantially more thancheaper and more efficient.
more than five-fold, with no sign thatthese estimates. However,
It may be that this percepthe rate of increase is leveling out.
what is more difficult totion was an illusion andestablish is whether curthe designs have become
rent estimated costs reallyno less complicated. The
are significantly higher than past costs and, if they need to provide protection against aircraft strikes
are, why estimated costs have increased at such also seems to have proved more onerous than thea rate.
nuclear industry anticipated.
The Sizewell B plant, the most recent plant built
in the United Kingdom, which did not encounter
major problems in the construction phase, costin the range of £3 billion, not out of line with cur-The figure of $1,000/kW may also not haveemerged “bottom-up” from design studies but
from “top-down” considerations that this was
the cost needed to make nuclear competitive. In

50short, the $1,000/kW was an imposed target withno technical basis. To the extent there has beencost escalation, a variety of explanations can besuggested for this 87. These include:
rapidly rising commodity prices driven by
China’s demands for them, which makes all power
plants more expensive, but affects nuclear plants
particularly severely because of their physical size;lack of production facilities, which meansthat utilities hoping to build nuclear plants are taking options on components like pressure vessels;
shortages of the necessary nuclear skills
as the nuclear workforce ages and is not replacedby younger specialists;
weakness of the US dollar; andgreater conservatism in cost estimation by
utilities.
All of these appear plausible at first sight,
but closer examination suggests not all are convincing.
Commodity prices. In the past decade,commodity prices of many metals and other raw
materials have increased significantly – the so-called
China effect. However, commodity prices havefallen sharply following the financial crisis with nocorresponding fall in estimated construction costs.
Component bottlenecks and skills shortages. Standard & Poor’s 88 places emphasis on theissue of shortage of component manufacturing
facilities. It identifies pressure vessels, circulatingwater pumps, and turbine forgings as particularly problematic. There is only one supplier, JapanThe Economics of Nuclear Power: An Update

Steel Works, which manufactures ultra-heavy forgings for pressure vessels. While a large demand
for these products would undoubtedly lead toan increase in capacity, the certification requirements for nuclear components will make this aslow process and companies will be reluctant tocommit the investment needed to build such production facilities until they see solid evidence oflong-term demand. Standard & Poor’s also notes
skills shortages as a major constraint and, again,such skills shortages cannot quickly or easily beovercome. It expects the United States to have torely on expertise from foreign countries, especially France and Japan initially.
Currency instability. Currency values
have been particularly volatile in the past two
years, with the dollar hitting historic lows against
European currencies. From November 2005 toJuly 2008, the value of the dollar against the euro
fell from €1=$1.17 to €1=$1.57. Yet by November
2008, the dollar had recovered much of thisground to €1=$1.27. It seems likely that at least
some of the cost escalation was related to the decline of the US dollar, making some inputs more
expensive in dollar terms but not necessarily ineuro terms.
Utility conservatism. Greater awareness among utilities regarding the accuracy of
their estimates and whether there will be serious
financial consequences is difficult to quantify.
Experience with Olkiluoto and the awareness that
regulators and the public are likely to be muchless indulgent to cost-overruns than they were in
the past will be a strong incentive for utilities tobuild-in ample contingencies.

87 For more discussion on these factors, see Standard & Poor’s, “Construction Costs To Soar for New U.S. 
Nuclear Power Plants” (2008).
88 Ibid.

51

9. Need for and extent of public subsidies

Successive studies by the British government
in 1989, 1995, and 2002 came to the conclusionthat in a liberalised electricity market, electricutilities would not build nuclear power plants
without government subsidies and government
guarantees that cap costs. In most countries where
the monopoly status of the generating companies
has been removed, similar considerations would
apply. The recent order in Finland clearly does
not follow this expectation, but, as argued above,the special status of the buyer as a not-for-profit
company owned by the industrial companies
contracted to buy the output of the plant meansthat the special conditions in Finland provide an
example that other countries are not likely to follow. The experience with this project has been
consistently very bad and this is likely to be a further deterrent to utilities operating in competitiveelectricity markets from building nuclear power
plants unless they are very fully insulated frommarket risks.
The US programme to revive nuclear ordering
has demonstrated that the key requirement forordering is either government-backed loan guarantees or a regulatory commitment to allow theutility to recover its costs from consumers. These

conditions allow utilities to borrow the money
they need very cheaply.
The areas where subsidies and guarantees
might also be required would be particularly
those that are not fully under the control of theowner. These include:
construction costs. The construction
costs of a new nuclear power plant would behigh and there would be a significant risk of costoverruns. The government might therefore have toplace a cap on the costs a private investor would
have to pay;
operating performance. There would
be a significant risk that performance would bepoorer than forecast. Reliability is largely under
the control of the owner and it is not clear whether
developers would be sufficiently confident intheir abilities to take the risk of poorer-thanexpected reliability;
non-fuel operations and maintenancecosts. Similarly, this is largely under the controlof the owners and they may be willing to bear
this risk;
nuclear fuel cost. Purchasing fuel has not
generally been seen as a risky activity. Uranium© Getty images/Jupiterimages

9. Need for and extent of public subsidies

52

can easily be stockpiled and the risk of increasing
the fuel-purchase cost can be dealt with. The costof spent-fuel disposal (assuming reprocessing is
not chosen) is, however, much more contentious,and nuclear owners might press for some form ofcap on disposal cost, similar to the US arrangements;
decommissioning costs. The costs ofdecommissioning are very hard to forecast, but thecosts will arise far into the future. Contributions
to a well-designed, segregated decommissioning fund appear relatively manageable, although
if experience with decommissioning and waste
disposal reveals that current estimates are significantly low, or if returns on investment of the fundare lower than expected, contributions might
have to be increased significantly. Private devel-

The Economics of Nuclear Power: An Update

opers might therefore seek some “cap” on theircontributions.
Guarantees would be particularly extensive
and high for the first units built, which would
bear the setup costs for a new technology. If a seriesof plants are built and experience with them isgood, it is possible that the market would be willing to bear more of the risk, although a politicalcommitment to promote nuclear power is by nomeans sufficient to ensure the completion of aprogramme. It should be remembered that the
Reagan and Thatcher administrations, which
promised a strong revival in the nuclear industry,
presided over steep declines in the fortunes ofnuclear power.

conclusionsconclusions
In the decade since the Nuclear Renaissancebased on Generation III+ designs was first mooted in the late 1990s, the forecast economics of
new nuclear plants has deteriorated dramatically.
Paradoxically, this seems to have made many governments, including those of the United States,
the United Kingdom, and Italy, far more determined to force new nuclear power plant orders
through. Indeed, the efforts to relaunch nuclear
ordering have been associated in a very personal way with the leaders of these countries: Bush,Blair, and Berlusconi.
While such powerful political backing can
be a strong facilitating force, for example shortcutting planning procedures and making public
subsidies available, it can also be a weakness.
When governments change, the new government
may be less enthusiastic.

53

these orders are generally being supplied bynational vendors and are generally for earlier
generation designs. The markets that must be
reopened if the Renaissance is to happen, suchas the United States, the United Kingdom and
Italy, are still several years away from orderingand the Generation III+ designs are also several
years from being demonstrated in operation.
While powerful political backing can push the
Nuclear Renaissance so far, if the fundamentals oftechnology and economics are not right, politicalbacking – as was provided by Thatcher and Reagan in
the 1980s – will ultimately not be enough. This reportfocuses on the economics, but there is an overlap
between economics and technology. In principle,
almost any design can be made to meet the safety
standards required by the regulatory authorities, but
the cost of doing so could be prohibitive.

Some of the enthusiasm for nuclear power
appears to be based on the blatantly misguided view that expanding nuclear power can be amajor way to cut emissions of greenhouse gases.
Electricity typically makes up only about 20% of
final energy demand, and even if this proportion
was increased somewhat and the proportion ofelectricity demand generated by nuclear power
was also increased, it would still be hard to get the
proportion of energy met by nuclear power much
above 10%. Increasing world nuclear capacity fouror five-fold would raise major issues – for example ofuranium resource adequacy, availability of acceptable sites, and waste disposal – even if the materials,
skills, and financial resources could be assembled.

It has proved much more difficult to obtainregulatory approval for the new designs thanwas expected. The US Nuclear Power 2010 programme was launched with an objective to get
a Generation III+ design on-line in the UnitedStates by 2010. It seems that only one design(AP1000) will have completed its design certification by then and even this design is now
being reviewed again following submission ofrevisions to it. By the start of 2010, it was clearthat none of the designs will be fully certified before 2011 and perhaps later. Significant
design issues – such with the Control andInstrumentation system for the EPR 89 and theShield Building for the AP1000 90– can likely beresolved, but in doing so, costs could be addedand delays will occur.

Worldwide, the ordering rate for new nuclear
power plants has been at a low ebb for 30 years.
In the past few years, orders for China and, to alesser extent, South Korea and Russia, have substantially increased the number of plants underconstruction – in January 2010, there were 20
plants under construction in China alone. But

There are three reasons why forecasting thecost of power from a nuclear plant is difficult andcontroversial:several of the variables relate to pro­
cesses that have not been proven on a commercial
scale, such as decommissioning and waste disposal, especially for intermediate- and high-level

89 For See for example, Health & Safety Executive, “Joint Regulatory Position Statement on the EPR Pressurized Water
Reactor”, Release No: V4 22/10/2009, November 2, 2009, http://www.hse.gov.uk/PRESS/2009/hse221009.htm
90 See for example, Nuclear Regulatory Commission, NRC Informs Westinghouse of Safety Issues with AP1000 Shield
Building, http://www.nrc.gov/reading-rm/doc-collections/news/2009/09-173.html

54

waste. Experience of nuclear power suggests that
unproven processes could easily cost significantly more than expected. There is therefore astrong risk that forecasts of these costs could besignificantly low;
for some of the variables, there is no “correct” answer. For example, the discount rate could
vary widely and there is no consensus on how provisions to pay for decommissioning should be set;
there is a lack of reliable, up-to-date data on
actual nuclear plants. Utilities are secretive about
the costs they incur, while in the past two decades,
there have been only a handful of orders in Western
Europe and none since 1980 in North America. All
modern designs are therefore untested.
Over the past four decades, there has consistently been a wide gap between the performance ofexisting nuclear plants and the performance forecast for new nuclear plants. These expectations havealmost invariably proved overoptimistic. The gap in
expected performance is as wide as ever between
current forecasts of the economic performance ofthe next generation of nuclear power plants andthat of the existing plants. The fact that in the past
such expectations have proved wrong is not a guarantee that current forecasts would prove inaccurate.
It does suggest that forecasts that rely on major
improvements in performance should be treatedwith some skepticism. The most important assumptions are:construction cost;
operating performance;
non-fuel operations and maintenance cost;
nuclear fuel cost;
decommissioning cost.
Nuclear power plants can only be built where
extensive government guarantees and subsidies
are provided.
There might also need to be commercial
guarantees that the output of the plants would bepurchased at a guaranteed price. It seems doubtful that such an extensive package of “state aids”
would be acceptable under EU competition law.

The Economics of Nuclear Power: An Update

There is a significant mismatch between thecommercial interests of the companies involved
and the interests of society in general. Costs incurred far in the future – no matter how large or
uncertain – have little weight in commercial cost
appraisals, and companies are also absolved of
the risk of nuclear accidents by international treaties. So cost appraisals made from a corporate
point of view must be corrected so that theyreflect fully the broader societal perspective.
As with the many previous predictions of a“second-comings” for nuclear power since 1980,
the result of the current “Renaissance” will not bea large number of new nuclear orders. Countries
where nuclear orders have not been problematic
will continue to order plants. Even in these countries, enthusiasm will dim as the escalating costs
become apparent, the problems of waste disposal
remain unaddressed, and nuclear capabilities
die away.
In the “Renaissance countries”, a handful ofplants will be built, proving only that nuclear power plants can be built if governments are prepared
to provide large enough subsidies and to override proper democratic consultation processes.
The real loss however will be – as it has been overthe past few decades – the opportunity cost of not
pursuing more cost-effective options of meetingthe energy policy goals of providing affordable,
reliable, and clean energy – or efficiency savings.
The cost-curve for nuclear power has always been
upwards. In other words, instead of getting cheaper over time due to the learning, scale economies,
and technical progress effects, as most technologies do, nuclear costs have increased. Analyses by
Froggatt and Schneider (2010) show that energy
efficiency and renewables are far more cost-effective than nuclear power and that their cost curveis downwards 91. If some of the resources being
poured into another fruitless attempt to revive
nuclear power were devoted to these sources,
the economic gap between energy efficiency andrenewables and nuclear would be highly likely togrow even wider.

91 A. Froggatt (with M. Schneider), “Systems for Change: Nuclear Power vs. Energy Efficiency and Renewables?” Paper
prepared for Heinrich Böll Foundation, April 2010.

Appendices

Appendicesappendix 1 :reactor technologies, current designs,
and vendors

Reactor technologies
Nuclear power reactors can be broadly categorised by the coolants and moderators they use. The
coolant is the fluid (gas or liquid) that is used to takethe heat from the reactor core to the turbine generator. The moderator is a medium that reduces thevelocity of the neutrons so that they are retained in
the core long enough for the nuclear chain reaction
to be sustained. There are many possible combinations of coolant and moderator, but among thereactors currently in service or on offer, there are
four possible coolants and three moderators.
The most common type of nuclear plant is thelight-water reactor (LWR), for which there are twovariants, the pressurised water reactor (PWR), andboiling water reactor (BWR). These are derived fromsubmarine propulsion units and use ordinary water(“light water”) as coolant and moderator. The advantage of water is its cheapness, although it is not themost efficient moderator (water molecules absorb
some of the neutrons rather than them “bouncing”
off the water). As a result, the proportion of theactive isotope of uranium has to be increased fromabout 0.7%, the amount found in natural uranium,
to more than 3%. This process is expensive.
As a coolant, the disadvantage of water is that
it is designed to work as a liquid. If there is a breakin the coolant circuit, the water will boil and willcease to be as effective as assumed. Avoiding thepossibility of “loss of coolant accidents” is therefore a major priority in reactor design. The maindifference between a PWR and a BWR is that ina BWR, the coolant water is allowed to boil andpasses directly to the turbine generator circuit,
where the steam generated in the reactor core
drives the turbine. In a PWR, the coolant water ismaintained as a liquid by keeping it under pressure. A heat exchanger (steam generator) is used
to transfer the energy to a secondary circuit wherewater is allowed to boil and drives the turbine.

55

BWRs are therefore less complex than PWRs, but
because the coolant water goes directly to theturbine, radioactive contamination of the plant
is more extensive. Most of the Russian-designed
plants, WWERs, are essentially PWRs. Britain has
one operating PWR, Sizewell B, but no BWRs.
Some plants use “heavy water” as coolant
and moderator, the most common of which are
the Candu reactors designed in Canada. In heavy
water, the deuterium isotope of hydrogen replaces
the much more common form of the atom. Heavy
water is a more efficient moderator and Candu
plants can use natural (unenriched) uranium.
However, its greater efficiency is counterbalancedby the cost of producing heavy water. A new Candu
design has been proposed that would use lightwater as a coolant and heavy water as a moderator,
but this design is still on the drawing board.
All of the British plants except Sizewell B
are cooled by carbon dioxide gas and moderated by graphite. The first-generation plants, theMagnoxes, use natural uranium, but most wereunable to operate long-term at their full design
rating because the carbon dioxide coolant
becomes mildly acidic when in contact withwater and causes corrosion of the piping. The
second-generation plants use enriched uranium
and improved materials were used to prevent corrosion. Graphite is an efficient moderator but isquite expensive compared to water. Its disadvantages are its flammability and its tendency to
crack and distort with exposure to radiation. The
design used at Chernobyl, the RBMK, also usesgraphite as the moderator but uses light water as
the coolant.
There has been consistent interest in reactorsthat use helium gas as the coolant and graphite
as the moderator, so-called high temperature
gas-cooled reactors (HTGRs). Helium is entirely
inert and is an efficient, albeit expensive coolant.
The use of helium and graphite means the reactor operates at a much higher temperature thana light-water or carbon-dioxide-cooled reactor.
This allows more of the heat energy to be turned
into electricity and also opens the way to usesome of the heat in industrial processes while still

56

The Economics of Nuclear Power: An Update

being able to generate power. However, despite
research in several countries – including Britain,
going back more than 50 years – no commercial
design of such a plant has ever been produced
and the demonstration plants that have been
built have a very poor record.
There has been some discussion of Genera­tion IV designs 92. While Generation III+ designs
are described by the US Department of Energy
as “evolutionary”, Generation IV designs aredescribed as revolutionary. They are described
as “safer, sustainable, economical, more proliferation resistant and secure”. The main feature ofthese designs that would distinguish them fromexisting designs is that they would use naturaluranium much more fully than existing technologies, for example, through use of “breeder
cycles”, which allow the 99.3% of natural uraniumthat existing reactors do not utilise, to be used.
They also operate at higher temperatures thanexisting reactors and could, for example, be used
to produce hydrogen. Six technologies have been
identified as being most promising:gas-cooled fast reactors;
lead-cooled fast reactors;
molten salt reactors;
sodium-cooled fast reactors;
super-critical water-cooled reactors;
very high-temperature gas-cooled reactors.
Only the sodium-cooled fast reactors and thevery high-temperature gas-cooled reactors haveseen significant development in operating plants.
However, both technologies have proved highly
problematic. Fast reactors cooled by sodium havebeen operated since the 1960s and many countries have had sodium-cooled breeder reactor
programmes, but they have proved very expensive and unreliable, and few countries are now
pursuing this technology. As noted above, hightemperature gas-cooled reactors have also been
under development in many countries since the1960s but have also proved impossible to commercialise, and most countries are no longer actively
pursuing them.

It remains to be seen whether any of thesetechnologies can be commercialised, but even
their proponents acknowledge that they will not
be a commercial option before about 2030, so they
have no relevance to current reactor choices.

Current designs and vendors
The most relevant designs for orders to beplaced in the next decade in the West are so-called
Generation III+. Generation I designs represent
the first orders placed in the 1950s and 1960s.
Generation II designs represent the majority ofunits now in service and include plants orderedfrom the late 1960s to the early 1980s. Generation
III plants are those ordered from the early 1980s
to around 2000. They incorporate, from the start,
the main lessons from the Three Mile Island accident. The main distinction between Generation
III plants and Generation III+ plants, which were
designed after the Chernobyl disaster, is thatthe latter incorporate a greater level of “passive”
safety as opposed to engineered safety. For example, Generation III+ designs would rely less onengineered systems for emergency cooling andmore on natural processes, such as convection.
The “9/11” attacks have added another importantdesign consideration and any new design must
now be able to demonstrate it can withstand acommercial aircraft being flown into it.
There are a large number of designs that havebeen announced, but many are not far advanced,
do not have regulatory approval, and have limited
prospects for ordering. There is no clear definitionof what Generation a particular design falls into,
but the main features of the Generation III+ design,
apart from it being designed in the last 15 years, are:a standardised design to expedite licensing, and reduce capital cost and constructiontime;
a simpler and more rugged design, making them easier to operate and less vulnerable tooperational upsets;
higher availability and longer operating
life – typically 60 years;

92 For more information on Gen IV technology, see the Generation IV International Forum at http://www.gen-4.org/

Appendices

reduced possibility of core-melt accidents;
minimal effect on the environment;
higher burn-up to reduce fuel use and theamount of waste; andburnable absorbers (“poisons”) to extend
fuel life 93.
These characteristics are clearly very imprecise and do not define well what differentiates a
Generation III+ plant from earlier designs, otherthan that the design was evolved from existingmodels. In the following descriptions, we concentrate on designs that have been ordered, or are
being assessed, by safety regulators.

Pressurised Water Reactors (PWR)
There are four main independent vendors of
PWR technology from which current designs arederived: Westinghouse, Combustion Engineering,
Babcock & Wilcox (B&W), and the Russian vendor, Rosatom.

57

numbers) had been overestimated. An executiveof Westinghouse justified the choice of a unit sizeof 600 MW rather than 1000-1300 MW by statingthat “the economies of scale are no longer operative”. 94 The AP-600 went through the US regulatory
process and was given safety approval in 1999. By
then, it was clear that the design would not be
economical and the AP-600 was never offered intenders. Its size was increased to about 1150 MW
in the hope that scale economies would make thedesign competitive. In September 2004, the NRC
granted a Final Design Approval, valid for five
years, to Westinghouse for the AP1000. The NRC
issued a standard Design Certification, valid for
15 years, in 2006. However, Westinghouse subsequently submitted further design changes thatwill not be approved by the NRC before 2011.
The AP1000 is one of the designs being reviewed
by the NII under its Generic Design Assessment(GDA) programme and the NII expects to complete its assessment by mid-2011, although, aswith the EPR, there is no guarantee that it willthen be licensed.

Westinghouse
Areva
Westinghouse technology is the most widelyused and has been widely adopted using technology licences, the main licencees being the
French company Areva (up to 2001, known as
Framatome), Siemens (Germany), and Mitsubishi(Japan). Westinghouse plants have been soldthroughout the world, although it had only one
order in the past 25 years (Sizewell B) before it
received four orders from China in 2008; its lastorder in the United States (not subsequently cancelled) was more than 30 years ago. In 1998, BNFL
took over the nuclear division of Westinghouse,but in 2006 it was sold to Toshiba. Westinghouse’s
main current design is the AP1000, although it has
only had orders for four units, all for China.
The AP1000 (Advanced Passive) was developed from the AP-600 design. The rationale for
the AP-600 was to increase reliance on passive
safety and also that scale economies (from building larger units as opposed to building larger

Both Framatome and Siemens became independent of Westinghouse and, in 2000, theymerged their nuclear businesses, with 66% of theshares going to Framatome and the remainder going to Siemens. Framatome is now controlled by the
Areva group, which is more than 90% owned by the
French government. The Framatome division was
renamed Areva NP in 2001. In 2009, Siemens expressed its intention to withdraw from the joint
venture, although by the end of 2009, the detailsof the withdrawal were still being negotiated.
Framatome supplied all the PWR plants in France(58 units) and has exported plants to South Africa,
South Korea, China, and Belgium. Siemens supplied 10 out the 11 PWRs built in Germany andexported PWRs to the Netherlands, Switzerland,
and Brazil.
The only Generation III+ PWR design withsignificant construction experience is the Areva

93 http://www.uic.com.au/nip16.htm
94 Nucleonics Week Special Report, “Outlook on Advanced Reactors”, March 30, 1989, p. 3.

58

The Economics of Nuclear Power: An Update

NP European Pressurised water Reactor (EPR).
The Finnish government issued a construction
licence for the Olkiluoto EPR in February 2005
and construction started in summer 2005. Work
started on an EPR at the Flamanville site in France
in 2007. Two EPRs have also been ordered by
China, but by the end of 2009, there was minimal
construction experience. The EPR received outline safety approval from the French authorities
in September 2004 and from the Finnish authorities in January 2005, although it is now clear, as is
discussed later, that many design details remain
to be finalised. Areva has asked the NRC, in collaboration with Constellation Energy, under the
Nuclear Power 2010 programme to begin licensing of the EPR in the United States. Final approvalis unlikely to be given before 2012. The EPR is also
one of the designs being reviewed by the UK safety authorities, the NII, under its GDA programme,
which was launched in 2007. The NII expects tocomplete its assessment by mid-2011, but thisdoes not mean it will necessarily be approved
then. For the US market, EPR is an abbreviation
for Evolutionary Power Reactor.
The Olkiluoto (Finland) EPR has an output of
1600 MW, although this was increased to 1700 MW
for orders after Olkiluoto. The design was developed from the previous Framatome design, N4,
with some input from Siemens’ previous design,
the “Konvoi” plant. A reduction in the refueling timeis expected to allow a load factor 95 of about 90%.

Mitsubishi
Mitsubishi supplies PWR technology to Japan,
where it has built 22 units, but it has never tried
to sell plants to the international market before
it submitted it to the US Nuclear Power 2010
process. One US utility is planning to build an
Advanced PWR (APWR), its most modern design.
Development of the APWR by Mitsubishi and its
technology licensor, Westinghouse, was launchedaround 1980, but first orders have continually
been delayed. Orders for a unit for the Tsuruga(Japan) site have been expected within about ayear for a decade, but as of the end of 2009 theorder had still not been placed. A more advanced
version of the APWR is being reviewed by the
NRC and one US utility, TXU, plans to order it.
The NII does not expect to complete its review
before about 2012.

Combustion Engineering
Combustion Engineering produced its own
design of PWR, which is installed in the UnitedStates. Outside the United States, its technology
was licensed by South Korea. The nuclear divisionof Combustion Engineering was taken over by
ABB in 1996 and, in turn, taken over by BNFL in
1999. It is now part of the Westinghouse division
and was sold in 2006 as part of the Westinghousedivision to Toshiba.
Combustion Engineering’s System 80+ design
received regulatory approval in the United Statesin 1997. System 80+ is not being offered for sale byWestinghouse. However, the South Korean vendor, Doosan, has used this design under licencefrom Westinghouse to develop its APR-1400,
which was ordered for South Korea in 2008. South
Korea did offer the design for the Generation III
plant tender held in 2005 for China but it was
rejected. In December 2009, it won a tender for
four units for installation in the United ArabEmirates and the suppliers are now expected tooffer it to Turkey.

Babcock & Wilcox
Babcock & Wilcox (B&W) supplied PWRs of its
own design to the US market, but the Three Mile
Island accident, which involved B&W technology,
effectively ended their interest in reactor sales.
The only plant of B&W design built outside theUnited States was built under licence in Germany,
but this was closed in 1988 due to licensing problems soon after its completion in 1986 and will
not be restarted.

95 Annual (or lifetime) load factor is calculated as the annual (or lifetime) output of the plant as a percentage of the output theplant would have produced if it had operated continuously at full power and is a good measure of the reliability of the plant.

Appendices

Rosatom/Atom Stroy Export
Exports of Russian technology are throughAtom Stroy Export (ASE), part of the Rosatom
company. In 2009, Siemens was negotiatingwith Rosatom to form a new joint venture tosell Russian technology. The latest Russian
design, generating about 1200 MW, is the AES2006/WWER-1200, offered from 2006 onwards.
Two units of this design have been ordered
for each of two sites in Russia (Leningrad andNovovoronezh). It won a tender in 2008 for nuclear plants to be built in Turkey, although it
was the only bidder and the contract was withdrawn in 2009 because of the high price offered.
It may be considered for Finland and India.

Boiling Water Reactors (BWRs)
The main designer of BWRs is the US company
General Electric (GE), which has supplied a large
number of plants to the USA and international
markets such as Germany, Japan, Switzerland,
Spain, and Mexico. Its licencees included AEG(subsequently taken over by Siemens), Hitachi,
and Toshiba. The Siemens reactor division (nowpart of Areva NP) offered the SWR design for the
Olkiluoto tender, but despite this, the design seems
some way from being commercially available.

GE-Hitachi and Toshiba
GE’s Japanese licencees continue to offer
BWRs in Japan. There are now 32 BWRs in operation or under construction in Japan. A few
first-of-a-kind plants in Japan were bought fromGE but the rest were split between Hitachi and
Toshiba. The Advanced Boiling Water Reactor(ABWR) was developed in Japan jointly by Hitachi
and Toshiba and their US technology licensor, GE.
The first two orders were placed around 1992 andcompleted in 1996/97. By the end of 2009, there
were four ABWRs in service and one under construction in Japan and two under construction in
Taiwan. The ABWR received safety approval in the
United States in 1997, but this approval runs out
in 2012. It is now being offered by a GE-Hitachi
joint venture and by Toshiba, which now operates independently, and both these companies

59

expect to submit an updated design to the NRC
to renew its safety approval. It is not known yet
how extensive the changes required by the NRC
would be and how long recertification would
take. Inevitably, the new design will need much
more extensive protection against aircraft strikes
than the earlier version. The ABWR should probably be classified as a Generation III design, but
if it succeeds in having its certification renewedby the NRC, the revised design can probably bedescribed as Generation III+. One utility, NRG,
plans to build ABWRs under the US Nuclear
Power 2010 programme.
The Economic & Simplified BWR (ESBWR) is
a 1500 MW design developed by GE. In October
2005, the GE-Hitachi joint venture applied to
the NRC for certification of the ESBWR design.
The ESBWR has been developed in part fromGE’s Simplified Boiling Water Reactor (SBWR)
and the ABWR. The SBWR began the process ofgetting regulatory approval in the 1990s but waswithdrawn before the procedure was complete
and did not win any orders. The ESBWR has
been chosen by a number of US utilities under
the Nuclear Power 2010 programme, although
NRC does not expect to complete its review
before 2011. The ESBWR was submitted to the
UK’s GDA review programme in 2007, but waswithdrawn in 2008. Six US utilities planned tobuild ESBWRs under the Nuclear Power 2010
programme, but one has switched to the ABWR,
one appears to have abandoned the project, andthere are doubts around the viability of most of
the other four projects. There appears to be little
interest in the ESBWR outside the United States
and the design may have to be abandoned.

Other BWRs
Asea Atom (Sweden) produced its own designof the BWR, nine of which were built in Sweden
and two in Finland. Asea Atom merged with
Brown Boveri to form ABB, which in turn was
taken over by BNFL in 1999 and sold to Toshibain 2006 as part of the Westinghouse nuclear division. The BWR-90+, a 1500 MW design developedby Westinghouse from the Asea BWR design, hasbeen mooted but development is not advanced.

60

The Economics of Nuclear Power: An Update

CandusThe main heavy-water reactor supplier is the
Canadian company Atomic Energy of Canada
Limited (AECL), which has supplied plants morethan 20 units to Canadian utilities as well as
exports to Argentina, Romania, South Korea, andChina. It also sold plants to India but because of
proliferation issues, it has had no contact with theIndians since 1975, although India continues tobuild plants of this 40-year-old design. Argentina
has built three heavy-water plants, one Candu
and two plants of a German design (one of whichis incomplete and no work is currently being carried out on it).
The main future design for AECL will be theAdvanced Candu Reactor (ACR), which was
expected to be produced in two sizes, 750 MW(ACR-700) and 1100-1200 MW (ACR-1000).
Unlike earlier Candus, which used heavy water
as a coolant and moderator, these would use
light water as a coolant and heavy water as amoderator. The ACR-700 was being reviewed by
the NRC under the sponsorship of the US utility
Dominion, but Dominion withdrew its supportin January 2005, opting instead for GE’s ESBWR,
citing the long time-scale of at least five years
that NRC said would be needed for the review
because of the lack of experience in the UnitedStates with Candu technology. The ACR-700
appears to have been subsequently abandonedin favor of the ACR-1000. Any calls for tenders
requiring a reactor of this size would probably
be offered an updated version of the 30-year-old
Candu-6 design. The ACR-1000 was offered in acall for tenders in Ontario but the price offered
was far too high. It was also submitted to the UK
GDA process in 2007 but was withdrawn soonafter. There are now proposals to privatise its
state-owned vendor, Atomic Energy of Canada
Limited (AECL), and the future of Candu technology for new orders is in doubt.

High-temperature gas-cooled
reactors (HTGRs)
It is not clear whether the HTGRs under development should be categorised as Generation III
or IV plants. The Pebble Bed Modular Reactor(PBMR) is based on designs developed bySiemens and ABB for Germany, but abandoned
after poor experiences with a demonstration
plant. It is now being developed by South Africaninterests. The various takeovers and mergers
in the reactor vending business mean that thetechnology licence providers are now Areva(for Siemens) and Westinghouse (for ABB). The
technology is being developed by PBMR Co., asubsidiary of Eskom, the South African publicly
owned electric utility. Funding for its development was contracted to come from Eskom; BNFL;
the US utility Exelon; and the South African stateowned Industrial Development Corporation.
This investment would entitle the companies
to a stake in a new company that would sell
the reactors. The project was first publicised in1998 when it was expected that first commercial
orders could be placed in 2003. However, there
were greater than anticipated problems in completing the design. Exelon withdrew in 2002 andthe other partners paid less than they were contracted to pay, leaving Eskom to bear most of thecosts up to 2004 and the South African government directly from then on. The BNFL option has
passed to Westinghouse, Industrial Development
Corporation has withdrawn, and no new investors have been found. The project time-scale
has slipped dramatically so that by 2009, firstcommercial orders were not expected until after
2025. In 2008, a report by the Jülich ResearchCentre – the German government’s nuclear
research organisation that first developed pebble bed technology – cast doubt on the safety ofthe design based on a reevaluation of experience
with a prototype plant of this design 96. In March
2009, the South African government announced
that it would provide only one more year of funding. PBMR Co. decided to effectively abandon
the design they had been developing. They may

96 R. Moormann, “A Safety Re-evaluation of the AVR Pebble Bed Reactor Operation and Its Consequences for Future HTR
Concepts”, Forschungszentrum Jülich, 2008, http://juwel.fz-juelich.de:8080/dspace/handle/2128/3136

Appendices61

now develop a much smaller design withoutsome of the advanced features, targeted at theprocess-heat market such as desalination, coalgasification, and liquefaction. It seems unlikelythat the PBMR programme will survive long after
the end of South African government funding.
Chinese interests are also developing similar technology with the same technological roots
and, while optimistic statements have been madeabout development there, the Chinese government seems to be backing development of PWRs
and perhaps BWRs.

Appendix 2
discounting, cost of capital, and required

now should be weighted more heavily than income
or expenditure earned in the future. For example,
a liability that has to be discharged now will cost
the full amount, but one that must be discharged
in, say, 10 years can be met by investing a smaller
sum and allowing the interest earned to make up
the additional sum required. In a DCF analysis,
all incomes and expenditures through time arebrought to a common basis by “discounting”. If an
income of $100 is received in one year’s time andthe “discount rate” is 5%, the “net present value” ofthat income is $95.23 – a sum of $95.23 would earn
$4.77 in one year to make a total of $100. The discount rate is usually seen as the “opportunity cost”
of the money, in other words, the rate of return(net of inflation) that would be earned if the sum ofmoney was invested in an alternative use.

rate of return

A particularly difficult issue with nuclear economics is dealing with, and putting on a common
basis for comparison, the streams of income andexpenditure at different times in the life of a nuclear
power plant. Under UK plans, the time from placinga reactor order to completion of decommissioning
could span more than 200 years.
Conventionally, streams of income andexpenditure incurred at different times are compared using discounted cash flow (DCF) methods.
These are based on the intuitively reasonableproposition that income or expenditure incurred

While this seems a reasonable process overperiods of a decade or so and with relatively low
discount rates, over long periods – with high discount rates – the results of discounting can be very
powerful and the assumptions that are being mademust be thought through. For example, if the discount rate is 15%, a cost incurred in 10 years of $100
would have a net present value of only $12.28. A
cost incurred in 100 years, even if the discount rate
was only 3%, would have a net present value of only
$5.20. At a discount rate of 15%, costs or benefits
more than 15 years forward have a negligible value
in an normal economic analysis (see Table 12).

Table 12 – Impact of discounting: net present values
3%

15%

5

0.86

0.50

10

0.74

0.25

15

0.64

0.12

20

0.55

0.061

30

0.41

0.015

50

0.23

0.00092

100

0.052

-

150

0.012

-

Discounting period (years)

Source: Author’s calculations

62

If we apply this to nuclear plants operating
in a competitive market where the cost of capital will be very high, this means that costs andbenefits arising more than, say, 10 years in the
future will have little weight in an evaluation of
the economics of a nuclear power plant. Thus
increasing the life of a plant from 30 years to 60
years will have little benefit, while refurbishment
costs incurred after, say, 15 years will equally
have little impact.
For decommissioning – for which under UK
plans the most expensive stage is not expected
to be started until 135 years after plant closure– this means very large decommissioning costs
will little impact, even with a very low discountrate that is consistent with investing funds in avery secure place with a low rate of return, such
as 3%. If we assume a Magnox plant will cost
about $1.8 billion to decommission and thefinal stage accounts for 65% of the total (undiscounted) cost ($1,170m), a sum of only $28
million invested when the plant is closed will
have grown sufficiently to pay for the final stageof decommissioning.
The implicit assumption with DCF methods is that the rate of return specified will beavailable for the entire period. Give that evengovernment bonds – usually seen as the most secure form of investment – are only available for30 years forward, and that a period of 100 yearsof sustained economic growth is unprecedented
in human history, this assumption seems difficult to justify.
So, with nuclear power, there is the apparent paradox that at the investment stage, avery high discount rate (or required rate of
return) of 15% or more is likely to be applied
to determine whether the investment will be
profitable, while for decommissioning funds,
a very low discount rate is applied to determine how much decommissioning funds canbe expected to grow.
The key element resolving this paradox
is risk. Nuclear power plant investment has
always been risky because of the difficulty of

The Economics of Nuclear Power: An Update

controlling construction costs, the variabilityof performance, the risk of the impact of external events on the operation, and the factthat many processes are yet to be fully proven (such as disposal of high-level waste anddecommissioning). In a competitive environment, there are additional risks because of
the rigidity of the cost structure. Most of thecosts will be incurred whether or not the plantis operated. Thus, while nuclear plants will dowell when the wholesale price is high (as was
the case with British Energy from 1996-1999),
they will do poorly when the wholesale priceis low (2000-2002). The fact that a plant has
made good profits for a decade will not protect
it from bankruptcy in the bad years, and financiers will therefore see investment in nuclear
power as being extremely risky and will apply
a very high interest rate that reflects the riskthat the money loaned could easily be lost.

Appendix 3
decommissioning

Decommissioning of nuclear plants has attracted considerable public interest in recent years asreactors get near the end of their lives, forecast
decommissioning costs escalate, and weaknesses
in the schemes that were meant to provide thefunds to do the job become apparent.
Conventionally, decommissioning is split
into three separate phases. In phase I, thefuel is removed and the reactor is secured.
The time taken to remove the fuel varies, withplants that refuel off-line taking much less time(e.g., PWRs and BWRs). These are designed
for about a third of the fuel to be replaced in
an annual shutdown of a few weeks. Reactorsthat refuel on-line (e.g., AGRs and Candus)
take much longer because the refueling machine is designed to constantly replace small
proportions of the fuel while the reactor is inoperation. This requires precision machinerythat moves slowly, and removing the entire
core may take several years. Once the fuelhas been removed, the reactor is no longer atrisk of a criticality and the vast majority of theAppendices

radioactivity and all the high-level waste has
been removed. Until this phase has been completed, the plant must essentially be staffed
as fully as if it was operating. There is thus astrong economic incentive to complete phase I
as quickly as possible, and phase I is invariably
completed as quickly as possible consistent
with safety. In technological terms, phase I issimple – it represents largely just a continuation of the operations that were being carriedout while the plant was operating. Note that
dealing with the spent fuel is not included in
the cost of phase I.
In the second phase, the uncontaminatedor lightly contaminated structures are demolished and removed, leaving essentially thereactor. Again, this is relatively routine workrequiring no special expertise. In economic
terms, the incentive is to delay it as long as
possible to minimise the amount that needs
to be collected from consumers to pay for
it – the longer the delay, the more interest
the decommissioning fund will accumulate.
The limiting point is when the integrity ofthe buildings can no longer be assured andthere is a risk they might collapse, leading toa release of radioactive material. In Britain, it
is planned to delay stage II until 40 years after
plant closure.
The third phase, the removal of the reactor
core, is by far the most expensive and most technologically challenging, requiring remote robotic
handling of materials. As with phase II, the economic incentive is to delay the work until it is nolonger safe to do so, and in Britain, this is expected to result in a delay of 135 years.
At the end of phase III, the ideal is that theland can be released for unrestricted use, in other words, the level of radioactivity is no higher
than in uncontaminated ground. In practice,
this is not always going to be possible and atsome “dirty” sites, such as the Dounreay sitein Scotland where a demonstration fast reactor operated, use of the land is expected to be
restricted indefinitely because of the high levelof contamination.

63

Very few commercial-size plants that haveoperated over a full life have been fully decommissioned, so the cost is not well established.
The operations required are said to have been
demonstrated successfully on a small scale, but
until they are applied to a large-scale plant, theprocess cannot be seen as proven – many processes that worked on a small scale in this area
have suffered problems when scaled up to commercial size.
Much of the cost of decommissioning isaccounted for by disposal of the radioactive waste
generated. The cost of waste disposal in modern
facilities is also not well-established, especiallyfor intermediate level waste and long-lived, lowlevel waste because of the lack of experience inbuilding facilities to take this waste.
This uncertainty is reflected in the way that
estimates of nuclear decommissioning costs
are quoted. Typically, they are quoted as a percentage of the construction cost (perhaps 25%).
Given that the cost of decommissioning clearly
only bears a limited relationship to the cost of
construction, this illustrates how little is knownof the costs.
A typical breakdown of the expected undiscounted cost of decommissioning might be
one-sixth for phase I, one-third for phase II,
and a half for phase III. British Energy was
required to operate a “segregated” fund to pay
for decommissioning of its plants, althoughphase I was expected to be paid for out of cash
flow. BNFL, which owned the Magnox plants
until they were transferred to the Nuclear
Decommissioning Authority in April 2005,
is publicly owned and treasury policy is not
to allow segregated funds for publicly owned
companies. British Energy assumed a discountrate of 3% for the first 80 years and zero after
then, while BNFL assumed a discount rate of
2.5% indefinitely. In 2003/04, British Energy
increased its discount rate to 3.5%.
If we assume a total cost of decommissioningof $1.8 billion – split between phases as above
with phase I carried out immediately after clo-

64

The Economics of Nuclear Power: An Update

Table 13 – Illustrative costs of decommissioning (£m)
Undiscounted

British Energy (3%)

British Energy (3.5%)

BNFL (2.5%)

Phase I

300

300

300

300

Phase II

600

184

151

223

Phase III

1,200

113

76

41

Total

1,800

597

527

574

Source: Author’s calculations

sure, phase II after 40 years, and phase III after
135 years – the undiscounted and discounted
costs will be as in Table 13.
British Gas-cooled reactors are expected to bevery expensive to decommission because of their
physical bulk, which produces a large amount ofwaste. PWRs and BWRs are much more compact
and are expected to cost perhaps only a third asmuch – for example, Sizewell B might be expected
to cost a total of about $540 million.
Various means are used so that, as required by
the polluter-pays principle, those that consume theelectricity produced pay for the decommissioning.
Under all methods, if the cost of decommissioning is underestimated, there will be a shortfall infunds that will inevitably have to be paid for by
future taxpayers. In Britain, the forecast cost ofdecommissioning the Magnox plants has grownby a factor of about four in the past 20 years, even
before any of the most challenging work has been
carried out.
The least reliable method of collecting thefunds is the unfunded accounting method underwhich the company makes accounting provisions
for the decommissioning. The provisions are collected from consumers but these funds are notseparated in any way from the company`s otherrevenues. The company is free to invest them inany way it sees fit, and these provisions exist as aproportion of the assets of the company, there is
not a specific pot of money or set of assets that is allocated to pay for decommissioning. This method
will only be reliable if it can be assumed the company will continue to exist until decommissioning
is completed and that the assets it builds make atleast the rate of return assumed. The weaknessof this method was illustrated when the Central
Electricity Generating Board – the company that
owned the power stations in England and Wales
until privatisation in 1990 – was privatised. About£1.7 billion in accounting provisions had been
made by consumers, but the company was sold for
only about a third of its asset value, so effectively
two-thirds of the provisions were lost. The government did not pass on any of the sale proceeds to thecompany that inherited the nuclear power plants,
losing the remainder of the provisions.
A more reliable method appears to be thesegregated fund. Under this method, consumers
make provisions for the duration of the plant’s life,
which are placed in a fund that the plant owner has
no access to and which is independently managed.
The funds are invested only in very secure investments to minimise the risk of loss of the funds. Suchinvestments might yield no more than 3% interest.
When decommissioning is required, the company
that owns the plant can draw down the segregatedfund. Again, there are risks as illustrated by British
experience. The British Energy segregated fund
did not cover stage I – by far the most expensive
stage in discounted terms (about half) – while thecompany collapsed long before the plants hadcompleted their operating life. The company had
to be rescued by the government, and much of
the burden of decommissioning will be borne by
future taxpayers, who will be required to provide
the funds when decommissioning is carried out.
Perhaps the lowest risk approach of provisions
being inadequate would be if a segregated fundwas set up at the time the plant entered service,with sufficient funds to pay for decommissioning

Appendices

after the design life of the plant had been completed. If we assume a life of 30 years and a discountrate of 3%, the required sum would be about 40% of
the undiscounted sum. Thus, if the undiscounted
decommissioning cost is about 25% of the construction cost, the sum that would have to be placedin the fund would be about 10% of the construction
cost. Even this scheme would be inadequate if theplant had to be retired early, or if the decommissioning cost had been underestimated or if thefunds did not achieve the rate of return expected.
Overall then, the sums required to decommission nuclear plants are likely to be high. But evenunder the schemes that provide the lowest risk that
there will be insufficient funds to pay for decommissioning – if the costs are estimated accurately– the impact on overall costs would appear to belimited because of the impact of discounting.

Appendix 4
status of the us projects

Southern Company
The Vogtle project appears to be the mostadvanced of the projects in the Nuclear Power2010 programme. In December 2009, the Vogtle
project (Georgia), comprising two AP1000s,
was seen as the frontrunner to get the first loan
guarantees to be offered by the US government. Ironically, two previous units at Vogtle,
completed in the 1980s, were among the worst
cases of cost escalation then. These two units,
originally expected to cost $660 million for four
units, escalated to $8.87 billion for the two units
actually built.
The NRC has given Southern Company permission to begin limited construction, for example
on backfill, retaining walls, and a waterproof
membrane at the Vogtle nuclear site 97. The NRC

65

also issued an “early site permit” to Southern that
determines the site is environmentally suitable
for the new reactors and approves emergency
plans. The Georgia Public Service Commission
accepted Georgia Power’s, which owns 45.7% of
the project, request to recover its financing costs
for its $6.4 billion share of the 2234-MW nuclear
project through “construction work in progress”
beginning in 2011 98. The assurance of cost recovery means that Southern Company has claimed itwill proceed with construction even if it does notreceive loan guarantees. It has also reduced the
expected cost of its share, including financing up
to $4.529 billion, or a total of $9.9 billion 99.

South Carolina Electricity & Gas
Like the Vogtle proposal, the Summer (South
Carolina) proposal is for two AP1000s and wason the US Department of Energie’s short-list
for loan guarantees. SCE&G estimated the costfor constructing the two Summer plants alone– without transmission and finance charges –would be $9.8 billion in June 2008 100. However,in January 2009, SCE&G increased the estimate
of its 55% share of the costs from $4.8 billion
to $6.3 billion, implying a total cost of $11.5
billion 101. This was described as an “all-in” priceand presumably includes finance costs.

Unistar
The Unistar consortium is a joint venture ofConstellation Energy (Baltimore Gas & Electric)
and EDF formed in 2007. EDF subsequently took
a 49.9% share in Constellation’s existing nuclear
assets. Unistar has three projects: Calvert Cliffs(Maryland), Nine Mile Point (New York), andElmore (Idaho), all for single EPRs. The mostadvanced of these is the Calvert Cliffs project,which was short-listed for loan guarantees. The
other two projects, Nine Mile Point and Elmore,
will not be actively progressed until there is some

97 Greenwire, “NRC Grants ‘Limited Work’ Approval for Proposed Ga. Reactors”, August 27, 2009.
98 Platts Global Power Report, “Georgia PSC Approves Two Nuclear Reactors by Georgia Power, and a Biomass Conversion”,
March 19, 2009.
99	 Nucleonics Week, “Georgia Power Lowers Estimate”.
100	 Nuclear Engineering International, “Power Market Developments – The American Way”, June 2008.
101	 SNL Power Week (Canada), “SCE&G Discloses New Costs for Summer Nuke Expansion”, January 5, 2009.

66

The Economics of Nuclear Power: An Update

prospect of loan guarantees being available forthem. In December 2009, Unistar asked the NRC
to put a hold on its application for a combined
construction and operating licence for Nine Mile
Point 102.The Elmore project is less advanced thanthe Nine Mile Point project. In April 2009, theChairman of UniStar said Constellation has not
publicly announced the estimated cost for Calvert
Cliffs and that those figures are confidential 103.

NRG
The South Texas project is for two ABWRs,
to be supplied by Toshiba, which replaced GEHitachi as the vendor of essentially the same
design in March 2008. It is the only project referencing the ABWR design, although some of the
projects referencing the ESBWR may switch to
the ABWR. It was short-listed for loan guarantees by the USDOE. This project attracted a great
deal of publicity in late 2009. Nuclear Innovation
North America (NINA) – a joint venture owned
88% by NRG and 12% by Toshiba – owns 50% of
the South Texas project. CPS, which is owned by
San Antonio city council, owns the other 50%.
However, in October 2009, CPS announced
its wish to reduce its stake to between 20 and
25% 104, and by December it was investigating
the possibility of exiting completely. This wasafter it emerged that Toshiba’s (the vendor) costestimate for the expansion project was about$4 billion higher than the $13 billion estimate
CPS had given city officials. CPS filed suit on
December 6 asking the court to clarify its rights
if it pulled out of the deal. The dispute escalated
on December 23 when NINA filed a suit that CPS
was in breach of contract and should lose thehundreds of millions of dollars it had invested.
CPS filed a counterclaim hours later for $32 billion, claiming that NRG and Toshiba had lured
CPS into the project through “fraudulent, defam-

atory and illegal conduct” and had then tried topush CPS out 105. In October 2009, it emerged thatthe cost estimate for the two South Texas ABWRs
was about $17 billion, including financing. No
up-to-date estimates without financing costs areavailable.

TXU Energy
The Comanche Peak (Texas) project is the only
proposal for the APWR. It was on the first USDOE
short-list for loan guarantees but was subsequently
relegated to first reserve. No construction costestimates for the Comanche Peak project have yet
been published.

Exelon Corporation
In November 2008, Exelon effectively abandoned the ESBWR for its Victoria site (Texas),
where two units were planned, and was reported
to be looking at alternative designs 106. In June
2009, Exelon announced it was deferring its
Victoria project for up to 20 years, although it wascontinuing with the Early Site Permit process 107.

Dominion
The North Anna project was one of the firstto be announced and was originally expected touse the Canadian ACR-700. However, in 2005,
Dominion announced it was abandoning theACR-700 in favor of the ESBWR. In January 2009,
Dominion announced it could not agree termswith GE-Hitachi for supply of the plant. Dominion
announced that it would “use a competitive
process” to see if vendors could provide a reactor for North Anna-3 “that can be licensed andbuilt under terms acceptable to the company 108”.
Dominion expects to make its decision about asupplier by the end of the first quarter in 2010.

102	 Nucleonics Week, “UniStar Puts Further Hold on Nine Mile Point-3”, December 10, 2009.
103	 Daily Record (Baltimore), “Constellation Energy CEO: French Firm Won’t Influence Baltimore Gas & Electric Co”,
April 28, 2009.
104	 Nucleonics Week, “NRG ‘Perplexed’ as CPS Explores Exiting Plan for New Texas Reactors”, December 10, 2009.
105	 San Antonio Express, “Mayor Calls for Meeting of Reactor Partners”, January 5, 2010.
106	 Nucleonics Week, “Exelon Drops ESBWR, Looks at Other Reactor Designs for Its Texas Project”, November 27, 2008.
107	 Greenwire, “Exelon Suspends Plans for Texas Plant”, July 1, 2009.
108	 Nuclear News, “Sales Talks Stall with Entergy, Dominion”, February 2009.

AppendicesEntergy
In February 2009, Entergy asked the NRC tosuspend reviews of its ESBWR applications at
Grand Gulf (Texas) and River Bend (Louisiana)
because of concerns about rising prices 109. Entergy
Chairman and CEO James Leonard said that thecompany “hit a brick wall” in negotiating an engineering, procurement, and construction contract
with GE Hitachi for the ESBWR because the pricerose to upward of $10 billion, which he called wellbeyond the original cost expectation 110.

Duke Energy
Duke’s Lee (South Carolina) project is for
two AP1000s. In September 2009, Duke said it
expected to begin operation of the first unit in
2021 and the second unit in 2023 – three years
later than originally planned 111. Duke Energy
estimated in November 2008 that the overnight
costs for the two-unit Lee station would be $11
billion – double its previous estimate 112.

Progress Energy
The Harris (N Carolina) project and the Levy
(Florida) projects are both for two AP1000s.
Progress has not been made on a commitment
to building these units. Progress’ tentative plan
is to begin commercial operation of the first of
the two planned Harris units in 2019 and thesecond in 2020. However, with lower demand
growth than forecast, Progress may choose
to be partners in either Duke’s or Dominion’s
projects. The Levy plants’ timelines have also
been pushed back, from completion in 2016/17
to 2019/20 113. Nevertheless, Progress Energy

67

has been authorised to collect nearly $207 million for construction and associated work on
Levy-1 and -2. This translates to an additional$5.86 per month for the average customer 114.
In February 2009, Progress estimated the construction cost of Levy would be $14 billion,
excluding transmission and connection costsof $3 billion 115.

AmerenUE
Ameren announced that it would withdraw
its EPR project at Callaway (Missouri), since “thecurrent legislation will not give us the financial
and regulatory certainty we need to complete thisproject 116”

DTE Energy
The DTE Energy project is for one ESBWR unit
at the Fermi (Michigan) site. It is reported that thecost would be about $10 billion, but it is not clear
what this cost includes 117.

PPL Corporation
PPL’s Bell Bend (Pennsylvania) project for asingle EPR is a joint venture between PPL as themain partner and Unistar. The website for the
project states that the cost of the project would
be $13–15 billion, including escalation, financing costs, initial nuclear fuel, contingencies, andreserves 118.

Amarillo PowerThe Amarillo project is for two EPRs and isalso a joint venture with Unistar, in this case,109	 Nucleonics Week, “Entergy Revises Construction Plans, Looks again to Acquisitions”, February 26, 2009, p. 1.
110 Nucleonics Week, “ESBWR Design Certification Rule To Be Completed in September 2011”, November 12, 2009.
111	 Nucleonics Week, “Duke May Push Back Startup of Lee Units”, September 10, 2009.
112	 WNN, “Duke Raises Cost Estimate for Lee Plant”, November 7, 2008.
113	 Inside NRC, “Potential AP1000 Buyers Unsure If NRC Design Finding Will Cause Delays”, October 26, 2009.
114	 Nuclear News, “The Florida PSC Approved Rate Recovery for New Reactors”, November 2009.
115	 Nuclear News, “EPC Contract Signed for Two AP1000s”, February 2009.
116	 Ameren, “AmerenUE Requests Sponsors to Withdraw Missouri Clean and Renewable Energy Construction Bills in General
Assembly”, press release, April 23, 2009, http://ameren.mediaroom.com/index.php?s=43&item=634
117	 Tina Lam, “DTE Applies for Another Nuclear Plant”, Detroit Free Press, September 19, 2008,
http://www.freep.com/apps/pbcs.dll/article?AID=/20080919/NEWS05/809190398
118	 http://www.bellbend.com/faqs.htm

68

The Economics of Nuclear Power: An Updatewith Amarillo Power. A combined Construction
and Operation License had not been applied forby the end of 2009.

FPL
The Turkey Point project is for two AP1000s.
In November 2009, the Florida Public Service
Commission (the state utility regulatory body)
approved FPL to begin collecting the construction cost of these two units from consumers in2010 119. The commission has approved FPL’s
recovery of $62.7 million in costs 120. FPL told theFlorida Public Service Commission that it forecast
an overnight construction cost for Turkey Pointin the range of $3,108-4,540/kW 121. However, in
September 2009, FPL said the expected range ofcosts had increased from $12.1-17.8 billion to$15-18 billion and, as a result, the completion
dates were likely to be pushed back from the 2018and 2020 dates already announced 122.

TVA

it is not subject to the state-level authority that
other utilities are. It also has better access tocapital and has no concerns about its credit
rating. It therefore does not require (and is
not eligible for) federal credit guarantees. It istherefore not a coincidence that it has been at
the forefront of efforts to restart nuclear ordering. The prospects for its two planned AP1000
units at the Bellefonte site – one of the earliest
identified projects under the Nuclear Power2010 programme – have been clouded by the
proposal by TVA to complete two partially built
units, on which work was stopped in the mid1980s. In December 2009, TVA published anenvironmental impact statement for different
expansion plans, but none of these included asecond AP1000 unit for Bellefonte, so it would
seem the second unit is effectively cancelled 123.
If the construction permits for the partially built
units can be reinstated, completing these may
be a much cheaper way to meet demand thanbuilding a new unit. TVA has estimated theovernight construction cost for the two AP1000
units would be $5.6-10.4 billion 124.

The Tennessee Valley Authority is very different to other US utilities because it is 100%
owned by the federal government. As a result,119	 Nuclear News, “The Florida PSC Approved Rate Recovery for New Reactors”, November 2009.
120	 Tenders Info, “United States: Florida Nuclear Utilities Recover Expansion Costs”, October 22, 2009.
121	 Nuclear Engineering International, “Power Market Developments”.
122	 Nucleonics Week, “FP&L Continuing with Plans to Build Reactors, but May Change Schedule.”
123	 Nuclear News, “TVA Announced the Issuance of Its Bellefonte Draft EIS”, December 2009.
124	 Chattanooga Times, “Estimates Rise”.

The Economics of Nuclear Power: An Update

Cost estimates for new nuclear plants have been escalating at
an alarming rate, and in the past decade, construction costestimates have increased five-fold, with every expectation thatcosts will increase further as the designs are firmed up. In addition, there are the unsolved problems of waste disposal andthe high susceptibility of the technology to failure. Up to now,
nuclear power plants have been funded by massive public subsidies. For Germany the calculations roughly add up to over
100 billion Euros and this preferential treatment is still goingon today. As a result the billions set aside for the disposal of
nuclear waste and the dismantling of nuclear power plants represent a tax-free manoeuvre for the companies. In addition theliability of the operators is limited to 2.5 billion Euros – a tiny
proportion of the costs that would result from a medium-sized

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nuclear accident. Yet, in recent years, governments have become
increasingly determined in their attempts to maintain existing
nuclear plants in service and revive nuclear ordering, on the
grounds that nuclear power is the most cost-effective way tocombat climate change. Some of this apparent paradox is relatively easily explained by the difference between the runningcosts only of nuclear power, which are usually relatively low,
and the overall cost of nuclear power – including repaymentof the construction cost – which is substantially higher. The
objective of this report is to identify the key economic parameters that determine the cost of nuclear electricity, commenting
on their determining factors. It shows that without subsidies
and guarantees from electricity consumers and taxpayers, newnuclear power plants will not be built.

The Economics of Nuclear
Power: An Update
By Steve Thomas