atw - International Journal for Nuclear Power | 02.2021
Ever since its first issue in 1956, the atw – International Journal for Nuclear Power has been a publisher of specialist articles, background reports, interviews and news about developments and trends from all important sectors of nuclear energy, nuclear technology and the energy industry. Internationally current and competent, the professional journal atw is a valuable source of information. www.nucmag.com
Ever since its first issue in 1956, the atw – International Journal for Nuclear Power has been a publisher of specialist articles, background reports, interviews and news about developments and trends from all important sectors of nuclear energy, nuclear technology and the energy industry. Internationally current and competent, the professional journal atw is a valuable source of information.
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2021
2
ISSN · 1431-5254
32.50 €
The World’s First
Power Plant
to Produce 400 Billion
Kilowatt Hours
Quo Vadis, Grid Stability?
Challenges Increase as
Generation Portfolio Changes
The Other End of the
Rainbow: Nuclear Plant
End-of-Life Strategies
Shaping Tomorrow’s Energy
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atw Vol. 66 (2021) | Issue 2 ı March
40, 60, 80, 100
3
The first generation of nuclear power plants was commissioned around 50 years ago. Today, 14 nuclear power plant
units worldwide have reached an operating age of more than 50 years, 92 of more than 40 years. During these five
decades, developments in the field of power plant technology and nuclear power plant engineering have continued
apace. Significant progress has been made in some areas, both in terms of optimising plant operation and in terms of
plant safety. Careful maintenance and renewal of systems and components as part of retrofits make a major contribution
to technical optimisation. In this way, existing nuclear power plants can also achieve safety levels that are required
for new plants, such as today's Generation III/III+. Another important aspect in terms of safety and operation is the
operating experiences. These are exchanged, analysed and used for further measures through the worldwide networking
of plant operators via bilateral contacts or via committees and activities of organizations such as the International
Atomic Energy Agency (IAEA), Nuclear Energy within the Organization for Economic Cooperation and Development
(OECD-NEA) or the World Association of Nuclear Operators (WANO). Today, the peaceful use of nuclear energy can
look back on some 19,000 years of plant operation, a wealth of experience that should not be underestimated.
EDITORIAL
The two Beznau nuclear power plant units in Switzerland
are impressive examples of how continuous plant maintenance
and optimisation can be achieved. Unit 1 went
into commercial operation on December 9, 1969, and Unit
2 on March 4, 1972. Since commissioning until today, the
operator Axpo Power AG has invested a total of around
2.5 billion Swiss francs in the safety and reliability of both
plants – construction originally cost CHF 700 million. In
the fall of 2020, IAEA Director Rafael Grossi visited the
plant to see the philosophy behind retrofits in Switzerland,
as agreed in the IAEA's Convention on Nuclear Safety.
Grossi noted that “the various safety upgrades at Beznau
NPP reflect the long-standing Swiss safety culture, which is
anchored in the principle of continuous improvement of
nuclear safety.”
Against this briefly outlined background, the question
arises as to when a nuclear power plant is “old” or has
reached its technical end of life. The experiences described
and, moreover, those in all countries worldwide that have
integrated nuclear energy into their strategies as part
of their energy mix with a long-term perspective show
that, on the one hand, “old” is to be seen rather with
“ experienced” and “reliable” for nuclear energy and
that “old” nuclear power plants can show considerable
perspectives for their operating times.
Another look at the USA
shows astonishing things!
For the background: Basis of the U.S. American licenses is
the U.S. Atomic Energy Act, which provides for time-fixed
licenses – irrespective of the requirement and control of
continuously guaranteed safety under consideration of
current technical developments. The initial operating
license is set for a term of 40 years. In addition, subsequent
applications can be made for an extension of operation for
20 years at a time. For both the initial license and
subsequent licenses for operating time extensions,
corresponding proof of plant safety must be available to
demonstrate reliability and safety for the entire license
period. What is not specified is the number of possible
subsequent applications. Similar models exist in many
other nuclear-using states, although the time periods for
initial and subsequent licensing can vary and can range
from 5 to 20 years.
The first application for a 20-year life extension in the
U.S. was submitted to the NRC – Nuclear Regulatory
Commission in April 1998 for the Calvert Cliffs nuclear
power unit. Since both the licensing authority and the
applicant had carefully prepared and worked out all steps
of the licensing process, including hearings and analyses
as well as evaluations of the application documents,
the application was approved in March 2000. Approved
applications for a total of 93 reactors followed to date, and
applications are still expected for three reactors. But that's
not all: in 2018, nuclear power plant operators submitted
follow-up applications for a total of four reactors for what
will then be 80 years of operation. These were approved in
2019 and 2020, respectively; applications for a further six
units and 80 years of total operating time are currently
before the NRC.
At the end of 2020, the NRC surprised again. It invited
the public to a meeting in January 2021 to enter into a
public dialogue related to the possible license extension
for 100 years of reactor operation. On the one hand,
this involves technical questions about whether such an
operating period may appear possible in principle,
identification of potential technical challenges and
prerequisites for such an operating period, and required
guidance documents that can assist the licensing authority
in its potential task.
100 years of operation – that means 100 years of
sustainability, resource conservation and emission
avoidance; a perspective in and for the future of a reliable
energy supply and policy!
Christopher Weßelmann
– Editor in Chief –
Editorial
40, 60, 80, 100
atw Vol. 66 (2021) | Issue 2 ı March
4
CONTENTS
Issue 2
2021
March
Contents
Editorial
40, 60, 80, 100 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Inside Nuclear with NucNet
Uranium Industry Told to Prepare for Improvement in Market Conditions . . 6
Did you know? 7
Calendar 8
Cover:
View of the Grohnde power plant site,
taken by a drone.
Feature | Operation and New Build 9
The World’s First Power Plant to Produce 400 Billion Kilowatt Hours . . . . . 9
Matthias Domnick, Sebastian von Gehlen, Stephan Kunze, Gerald Schäufele, Dietmar Schütze and Ralf Südfeld
Interview with Mikhail Chudakov
“LTO Is Not Only Significantly Cheaper Than Nuclear
New Build Projects, But Is Actually the Cheapest Option
for Power Generation Across the Board” . . . . . . . . . . . . . . . . . . . . . 13
Serial | Major Trends in Energy Policy and Nuclear Power
Quo Vadis, Grid Stability?
Challenges Increase as Generation Portfolio Changes . . . . . . . . . . . . . . 16
Kai Kosowski and Frank Diercks
Energy Policy, Economy and Law
Challenges and Perspectives for Long-Term Operation in Switzerland. . . . 27
Natalia Amosova
From Fossil Fuel Super Power to Net Zero –
Can Australia Deliver an Orderly Energy Transition? . . . . . . . . . . . . . . . 30
Dayne Eckermann, Oscar Archer and Ben Heard
Extending Nuclear Plant Licenses to 80 Years –
Essential to Achieve a Reliable Future Energy Mix . . . . . . . . . . . . . . . . 37
James Conca
Site Spotlight
Beznau Nuclear Power Plant –
Decades of Safe, Environmentally Friendly Power Generation . . . . . . . . 40
Decommissioning and Waste Management
The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies . . . . 46
Edward Kee, Ruediger Koenig and Geoff Bauer
Ground Control and the Principle of Minimizing Radiological
Exposure as Key Drivers for the Recovery
of Radioactive Waste Out of the Asse II Mine . . . . . . . . . . . . . . . . . . . 57
Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
At a Glance
Deep Isolation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
Research and Innovation
Assessment of Loss of Shutdown Cooling System Accident
during Mid-Loop Operation in LSTF Experiment using SPACE Code . . . . . 66
Minhee Kim, Junkyu Song, Kyungho Nam
News 70
Nuclear Today
Biden Includes Nuclear in his Climate Toolkit –
But Can he Build Back Better on Waste Policy? . . . . . . . . . . . . . . . . . . 74
Imprint . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Contents
atw Vol. 66 (2021) | Issue 2 ı March
5
Feature
Operation and New Build
9 The World’s First Power Plant
to Produce 400 Billion Kilowatt Hours
CONTENTS
Matthias Domnick, Sebastian von Gehlen, Stephan Kunze,
Gerald Schäufele, Dietmar Schütze and Ralf Südfeld
Interview with Mikhail Chudakov
13 “LTO Is Not Only Significantly Cheaper Than Nuclear New Build
Projects, But Is Actually the Cheapest Option for Power Generation
Across the Board”
Serial | Major Trends in Energy Policy and Nuclear Power
16 Quo Vadis, Grid Stability?
Challenges Increase as Generation Portfolio Changes
Kai Kosowski and Frank Diercks
Energy Policy, Economy and Law
30 From Fossil Fuel Super Power to Net Zero –
Can Australia Deliver an Orderly Energy Transition?
Dayne Eckermann, Oscar Archer and Ben Heard
Decommissioning and Waste Management
46 The Other End of the Rainbow:
Nuclear Plant End-of-Life Strategies
Edward Kee, Ruediger Koenig and Geoff Bauer
57 Ground Control and the Principle of Minimizing Radiological
Exposure as Key Drivers for the Recovery of Radioactive Waste Out
of the Asse II Mine
Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
Contents
atw Vol. 66 (2021) | Issue 2 ı March
6
INSIDE NUCLEAR WITH NUCNET
* million, m = 10 6
billion, bn = 10 9
Uranium Industry Told to Prepare
for Improvement in Market Conditions
Sufficient resources exist for the nuclear industry, but the Covid-19 pandemic
could hit supplies, says latest edition of Red Book
Global uranium resources have increased, but more modestly than in previous years, with the
industry being urged to prepare to bring mines idled by the Covid-19 pandemic back into service if
market conditions improve in an effort to increase capacity.
The latest edition of “Uranium – Resources, Production
and Demand”, also known as the “Red Book”, shows that
the world’s conventional identified uranium resources
amounted to about eight million* tonnes of uranium metal
(tU) as of 1 January 2019. This figure represents all
reasonably assured and inferred uranium resources that
could be recovered at market prices ranging from $40 to
$260/kgU (equivalent to $15 to $100/lb U 3 O 8 ).
Compared to the total reported in the 2018 edition, this
is an increase of only 1 %. A small portion of the overall
changes in identified resources relate to new discoveries.
Additions to the uranium resource base could come from
yet undiscovered or unconventional resources, such as
uranium from phosphate rocks.
Global uranium mine production decreased by 10.8 %
from 2017 to 2018 due to production cuts resulting from
poor market conditions but increased slightly by 1 %
to 54,224 tU in 2019. Furthermore, planned uranium
production cuts in early 2020 were deepened by the onset
of the Covid-19 pandemic, and its effects could be felt
through 2021 and beyond.
Kazakhstan was the top producer in 2019 with
22,808 tU, followed by Canada (6,944 tU), Australia
(6,613 tU), Namibia (5,103 tU) and Uzbekistan (3,500 tU).
These top five producers were responsible for 82 % of total
production.
The Red Book shows that 57.4 % of uranium ore is
produced using in situ leaching, or ISL, also called in-situ
recovery (ISR) or solution mining. ISL is a mining process
used to recover minerals such as copper and uranium
through boreholes drilled into a deposit, in situ. It works by
artificially dissolving minerals occurring naturally in a solid
state. Open pit mining (20 %) and underground mining
(16.1 %) are the second and third most common methods.
Australia leads the way in recoverable resources with
slightly over two million tU, representing 25 % of the
world’s total. Kazakhstan is second with 969,200 tU and
Canada third with 873,000 tU.
World annual uranium requirements were 59,200 tU as
of January 2019, almost 5,000 tU more than the volume
produced. Kazakhstan’s state-owned uranium company
Kazatomprom produced the most with 22 % of the world’s
total. Orano of France was second with 11 % followed by
Cameco of Canada with 9 %.
Continuing a downward trend over several years,
worldwide domestic exploration and mine development
expenditures decreased to approximately $500m in 2018,
a significant drop from $2bn in 2014. This trend is not
expected to result in shortfalls but could signal market
issues in the longer-term.
According to the Red Book, sufficient uranium resources
exist to support the long-term use of nuclear energy for
electricity generation and other uses such as industrial
heat applications and hydrogen production, but the impact
of the Covid-19 pandemic could affect supplies.
The Red Book, prepared jointly on a biennial basis by
the Nuclear Energy Agency and the International Atomic
Energy Agency, says uranium production cuts have been
unexpectedly deepened with the onset of the global
Covid-19 pandemic in early 2020.
It says: “In the wake of recent significant reductions in
uranium production and the effects of Covid-19, the
coming challenges are likely to be those associated with
constrained investment capabilities, as a result of
depressed market conditions that will push the industry to
optimise its activities still further.”
The pandemic has led to mining restrictions in a number
of markets including Kazakhstan, Canada, the US, Namibia
and Australia.
The Red Book warns that effects related to efforts to
slow the spread of the Covid-19 virus at production
facilities will likely lead to a further, unplanned reduction
in production that will test the market’s ability to continue
supplying an adequate supply of uranium to the global
nuclear fuel supply chain. “As such, 2020 uranium
production targets may be a challenge to achieve, and the
consequences of pandemic-related restrictions on mining
and milling could be felt through 2021, constricting global
supply of newly mined uranium.”
Investment in innovative mining and processing
techniques would help assure that uranium resources are
brought to market when they are needed.
While some uranium producers reduced activities at
some facilities, others opted to close operations until
market conditions improve sufficiently to justify reopening.
The resources and annual production capacity of
these temporarily closed operations, referred to as idled
mines, are examined for the first time in the 2020 edition
of the Red Book. The report suggests that annual production
capacity could increase relatively quickly by
bringing these idled mines back into service if market
conditions improve.
The Red Book also provides projections for nuclear
power generation uranium requirements through 2040.
While nuclear capacity projections vary considerably from
region to region, growth in the nuclear sector and in
uranium requirements are projected to be the largest in the
East Asia region.
Author
David Dalton
NucNet,
Bruxelles, Belgium
Inside Nuclear with NucNet
Uranium Industry Told to Prepare for Improvement in Market Conditions
atw Vol. 66 (2021) | Issue 2 ı March
Power generation base in Germany now set for decline
In January the German grid regulator Bundesnetzagentur
( BNetzA) and the antitrust agency Bundeskartellamt published
their annual Monitoring Report 2020 (Energy Monitoring Report
2020) on the electricity and gas markets and respective infrastructures
for 2019/2020 with some corona-incurred delay but
thereby including some 2020 data. Among many other subjects
the report shows (see graph below), that conventional net power
generation capacity in Germany hardly changed between 2014
and 2020 despite the additional shut-down of three large nuclear
power plants in this period and the decommissioning of older
fossil fuel power plants. At the same time the installed base of
renewable generation increased steadily, corresponding to an
increasing share of renewable net generation that rose from
27.5 per cent in 2014 to 46.3 per cent in 2020. For 2020 of course
this was aided by a significant decline of net generation due to
the economic slow down related to the corona pandemic that did
not affect renewables.
There are several reasons for the steadiness of installed conventional
generation till 2020: for once, several new power plants –
often planned many years ago – came online such as the
Moorburg coal power plant (1,600 MW, 2016) and the Datteln IV
coal power plant (1,052 MW, 2020). Then some older lignite
plants with 2.7 GW capacity were taken out of the regular
electricity market but not from the grid thus entering the state of
so called safety standby. Also there is a category that might be
considered as "zombie" power plants: these are plants for which
the operator announced the desire for permanent shut down
already but that were ordered by the grid regulator to remain
disposable and in the state of so called grid reserve. This state is
de facto similar to safety standby, but with unlimited duration.
Only plants in the south of Germany are affected where
generation capacity has been scarce ever since the accelerated
phase-out of nuclear started in 2011. Some 6 GW of fossil power
plants are concerned currently, 2.7 GW of which are older than
40 years with the oldest one dating back to 1954.
Now the situation starts to change: not only will nuclear phaseout
soon be completed in two steps at the end of 2021 and 2022
reducing capacity by 8.1 GW but also the phase-out of coal takes
up pace. The first tendering process for coal power plant phaseout
resulted in accepted bids for compensation for 4.8 GW
capacity, the largest part of which will be withdrawn from power
generation till the end of 2021. The plants in safety standby will
be retired definitly in several steps till Octobre 2023, and an
additional 2.8 GW lignite plants will close till the end of 2023.
Despite 2.4 GW of new fossil capacity expected to go online in
the same time frame, the grid regulator expects a net loss of net
conventional capacity in Germany from now till the end of 2023
of 15.6 GW. This compares to a total conventional capacity
reduction of just 4.6 GW during the past seven years.
Another interesting aspect is the comparison between past
investment and expected expenditures to adapt the transmission
grid to the changing generation landscape, i.e to integrate
renewables and compensate for the changes in network topography
related to nuclear and coal phase-outs. From 2015 to
2019 the annual investment expenses of TSOs in Germany varied
between 3.1 and 3.6 billion Euro. The target figure for 2020 is
5.3 billion Euro. The cost estimate for the period 2021 to 2035
though that is given by TSOs in the latest grid development plan
for 2035 ranges between 105 and 115 billion Euro for the period
which means an annual figure of some 7.3 billion per year. This
covers only the highest grid level operated by the four TSOs
including the off-shore grid but excluding all investment in the
distribution grid at all levels.
7Did you know?
DID YOU EDITORIAL KNOW? 7
Installed Power Generation Capacity (net) in Germany in GW
250
200
150
100
196.4
90.3
204.9
97.7
211.8
104.2
215.6
111.6
221.3
118.2
226.4 229.2
124.4 127.7
Sources:
Monitoringbericht 2020
(Energy Monitoring
Report 2020), Bundesnetzagentur
(BNetzA),
Bundeskartellamt,
January 2021; Netzentwicklungsplan
Strom
2035, Version 2021,
1. Entwurf, German
TSOs, January 2021;
Kraftwerksliste, BNetzA,
January 2021; Stromerzeugung
und -verbrauch
in Deutschland,
BDEW, December 2020
50
0
106.1 107.1 107.6 104.0 103.1 102.0 101.5
2014 2015 2016 2017 2018 2019 2020
Nuclear Lignite Coal Natural Gas Oil Pumped Storage Waste Other Renewables
For further details
please contact:
Nicolas Wendler
KernD
Robert-Koch-Platz 4
10115 Berlin
Germany
E-mail: presse@
KernD.de
www.KernD.de
Did you know?
atw Vol. 66 (2021) | Issue 2 ı March
8
CALENDAR
Calendar
2021
Virtual Conference 08.03. – 12.03.2021
WM2021 – Waste Management Symposia.
X-CD Technologies, www.wmsym.org
Virtual Conference 16.03. – 18.03.2021
EURAD 1 st Annual Event.
www.ejp-eurad.eu
Virtual Conference 23.03. – 26.03.2021
ETRAP – 7 th International Conference on
Education and Training in Radiation Protection.
FuseNet, www.etrap.net
Virtual Conference 05.04. – 08.04.2021
INBP – Indian Nuclear Business Platform.
NBP, www.nuclearbusiness-platform.com
Virtual Conference 13.04. – 15.04.2021
World Nuclear Fuel Cycle. WNA World Nuclear
Association, www.wnfc-event.com
Virtual Conference 19.04. – 22.04.2021
AFNBP – African Nuclear Business Platform.
NBP, www.nuclearbusiness-platform.com
Virtual Conference 20.04. – 21.04.2021
Nuclear Decommissioning and Waste
Management 2021. Prospero Events Group,
www.virtual.prosperoevents.com
Cancelled due to COVID 03.05. – 07.05.2021
ATALANTE 202(0)1. Nimes, France, CEA + Geniors,
www.atalante2020.org
04.05.2021
2021 KTG Annual Meeting. Berlin, Germany, KTG,
www.ktg.org
Virtual Conference 10.05. – 15.05.2021
FEC 2020 – 28 th IAEA Fusion Energy Conference.
Nice, France, IAEA, www.iaea.org
Virtual Conference 01.06. – 02.06.2021
Nuclear Power Plants IV. Expo & VIII. Summit
(NPPES). Istanbul, Turkey, INPPES Expo,
www.nuclearpowerplantsexpo.com
Virtual Conference 02.06. – 04.06.2021
HTR2021 – 10 th International Conference
on High Temperature Reactor Technology.
Yogyakarta, Indonesia, Indonesian Nuclear Society,
www.htr2020.org
07.06. – 11.06.2021
International Conference on Geological
Repositories. Helsinki, Finland, EURAD,
www.ejp-eurad.eu
Postponed to 09.06. – 11.06.2021
International Forum on Enhancing a Sustainable
Nuclear Supply Chain. Helsinki, Finland, Foratom,
https://events.foratom.org/mstf2021
13.06. – 16.06.2021
2021 ANS Annual Meeting. ANS, Providence, RI,
USA, www.ans.org
23.06. – 24.06.2021
Maintenance in Power Plants 2021. Karlsruhe,
Germany, VGB PowerTech e.V., www.vgb.org
Virtual Conference 03.08.-04.08.
and 10.08.-11.08.2021
International Uranium Digital Conference 2021.
AusIMM, www.ausimm.com
Virtual Conference 04.08. – 06.08.2021
ICONE 28 – 28 th International Conference on
Nuclear Engineering. Nuclear Energy the Future
Zero Carbon Power. ASME, https://event.asme.org
25.08. – 27.08.2021
KONTEC 2021 – 15 th International Symposium
“Conditioning of Radioactive Operational &
Decommissioning Wastes”. Dresden, Germany,
atm, www.kontec-symposium.de
25.08. – 03.09.2021
The Frédéric Joliot/Otto Hahn Summer School
on Nuclear Reactors “Physics, Fuels and Systems”.
Aix-en-Provence, France, CEA & KIT, www.fjohss.eu
Postponed to 30.08. – 03.09.2021
International Conference on Operational Safety
of Nuclear Power Plants. Beijing, China, IAEA,
www.iaea.org
22.09. – 23.09.2021
VGB Congress 100 PLUS. Essen, Germany, VGB
PowerTech, www.vgb.org
27.09. – 30.09.2021
European Nuclear Young Generation Forum
(ENYGF). Tarragona, Spain, ENYGF, www.enygf.org
27.09. – 01.10.2021
NPC 2021 International Conference on Nuclear
Plant Chemistry. Antibes, France, SFEN Société
Française d’Energie Nucléaire,
www.sfen-npc2021.org
04.10. – 05.10.2021
AtomExpo 2021. Sochi, Russia, Rosatom,
http://2021.atomexpo.ru/en
Virtual Conference 04.10. – 06.10.2021
ICEM 2021 – International Conference on
Environmental Remediation and Radioactive
Waste Management. ANS, www.asme.org
Postponed to 24.10. – 28.10.2021
TopFuel 2021. Santander, Spain, ENS,
https://www.euronuclear.org/topfuel2021
26.10. – 28.10.2021
VGB Conference Chemistry. Ulm, Germany, VGB
PowerTech, www.vgb.org
01.11. – 12.11.2021
COP26 – UN Climate Change Conference.
Glascow, Scotland, www.ukcop26.org
Postponed to 30.11. – 02.12.2021
Enlit (former European Utility Week and
POWERGEN Europe). Milano, Italy,
www.enlit-europe.com
30.11. – 02.12.2021
WNE2021 – World Nuclear Exhibition. Paris,
France, Gifen, www.world-nuclear-exhibition.com
2022
Postponed to 28.02. – 04.03.2022
20 th WCNDT – World Conference on
Non-Destructive Testing. Incheon, Korea,
The Korean Society of Nondestructive Testing,
www.wcndt2020.com
18.05. – 20.05.2021
Power Uzbekistan 2021 – 15 th Anniversary
International Exhibition on Energy.
Tashkent, Uzbekistan, Iteca Exhibitions,
www.power-uzbekistan.uz
Postponed to 30.05. – 05.06.2021
BEPU2020 – Best Estimate Plus Uncertainty
International Conference, Giardini Naxos.
Sicily, Italy, NINE, www.nineeng.com
Postponed to 08.09. – 10.09.2021
3 rd International Conference on Concrete
Sustainability. Prague, Czech Republic, fib,
www.fibiccs.org
08.09. – 10.09.2021
World Nuclear Association Symposium 2021.
London, UK, WNA, www.wna-symposium.org
15.09. – 17.09.2021
NUWCEM 2021 – International Symposium on
Cement-Based Materials for Nuclear Wastes.
Avignon, France, SFEN, www.sfen-nuwcem2021.org
29.03. – 30.03.2022
KERNTECHNIK 2022.
Leipzig, Germany, KernD and KTG,
www.kerntechnik.com
Postponed to Spring 2022
4 th CORDEL Regional Workshop – Harmonization
to support the operation and new build of NPPs
including SMR. Lyon, France, World Nuclear
Association, https://events.foratom.org
This is not a full list and may be subject to change.
Calendar
atw Vol. 66 (2021) | Issue 2 ı March
The World’s First Power Plant
to Produce 400 Billion Kilowatt Hours
Matthias Domnick, Sebastian von Gehlen, Stephan Kunze, Gerald Schäufele,
Dietmar Schütze and Ralf Südfeld
Introduction When it first synchronised with the power distribution network at 14:11 hrs on 5 September 1984,
Grohnde nuclear power plant (KWG) started to write its own success story. Since it was first commissioned, the
pressurised water reactor has eight times been World Champion in annual electricity generation. Even today, Grohnde
NPP still produces a good 12 % of the electricity generated in Lower Saxony, thereby helping to stabilize the electricity
supply in Germany.
And yet another record was recently added to this
impressive list. On 7 February 2021, KWG was the first
power plant unit in the world to produce its 400 billionth
kilowatt hour of electricity. No other nuclear power plant
unit in the world has produced more electricity.
This amount of electricity would have supplied the
whole of Germany for nine months (based on the 2019
figure of 512 TWh).
Highly efficient and climate-friendly
One of the greatest challenges of our time is to reduce
emissions of climate-damaging greenhouse gases, especially
carbon dioxide (CO 2 ). Here KWG scores again: as compared
to conventional forms of electricity generation, Grohnde
has saved approximately 400 million tonnes of CO 2 over its
36 years of safe and successful operation.
The workforce of Grohnde NPP can look back with
pride at this achievement, which they and their contractors
have maintained for nearly 40 years. The high electricity
production and availability of KWG can only be achieved
by qualified and highly motivated staff, a reliable plant and
continuous improvement of safety standards. The success
of these strategies is evidenced by all the national and
international safety audits, which confirm the high level of
safety of the entire plant.
Operation
Due to the increasing proportion of fluctuating solar and
wind energy being fed into the electricity network, it has
become increasingly important to safeguard its stability.
Grohnde NPP has responded to this situation over the
years by increasing its reactor output, improving efficiency,
increasing load gradients and also by installing adaptive
power distribution control technology in April 2016.
Over nearly 40 years of operation, the nuclear power
plant has proved to be a reliable partner to network
operators. Whereas, in the first few years, it mainly provided
a stable base-load power, over the latter years it increasingly
provided system services (standby work). For example, in
2020, Grohnde NPP not only provided 379,652 MWh
(11 full-load days) of standby work but also stabilised the
network for 4,700 hours by participating in redispatch or via
primary and secondary control upon request of the grid
operator TenneT.
Safety analysis and review
Article 19a of the Atomic Energy Act (AtG) requires that a
Safety Review (SR) must be conducted to supplement
ongoing regulatory supervision and to establish the current
safety status of a nuclear power plant. A Safety Review
for KWG was first submitted for assessment in 2000.
In keeping with the defined 10-year rhythm, the second
safety review – consisting of an up-to-date description of
the entire plant, a deterministic Safety Status Analysis
(SSA), a Level 1 Probabilistic Safety Analysis (PSA) and a
Deterministic Security Analysis for Nuclear Power Plants
(DSA) – as defined by the guidelines from the Federal
Ministry for the Environment, Nature Conservation and
Nuclear Safety (BMU) – was compiled and submitted for
assessment in 2010. The deterministic Safety Status
Analysis comprised a protective-goal-oriented analysis of
the control of events of the relevant accident spectrum by
9
FEATURE | OPERATION AND NEW BUILD
14.0
400.0
12.0
350.0
10.0
8.0
6.0
4.0
300.0
250.0
200.0
150.0
100.0
2.0
50.0
0.0 0.0
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
| Annual production and cumulative production
Feature
The World’s First Power Plant to Produce 400 Billion Kilowatt Hours ı Matthias Domnick, Sebastian von Gehlen, Stephan Kunze, Gerald Schäufele, Dietmar Schütze and Ralf Südfeld
atw Vol. 66 (2021) | Issue 2 ı March
FEATURE | OPERATION AND NEW BUILD 10
| Grohnde nuclear power plant: view of the reactor building with the two cooling towers in
the background. (Photo: Bernhard Ludewig)
checking worst-case failure calculations. The existing
calculations were checked and supplementary worst-case
failure calculations were done. This once again confirmed
the plant’s high safety level.
Another component of the SSA was an evaluation of
operating experience and statements from the plant
management. It was demonstrated that there is a strong
safety culture within the organisation and the requirements
imposed for Safety Levels 1 and 2 are fulfilled in
terms of guaranteeing reliable operation to prevent
accidents. Moreover, the deterministic Safety Status
Analysis confirmed that the postulated Safety Level 3
events are effectively and reliably controlled by the safety
systems installed in KWG.
It was shown that the necessary equipment and
measures are in place to control extremely rare, beyonddesign-basis
plant conditions of Safety Level 4.
The Level 1 Probabilistic Safety Analysis (PSA) constitutes
a major part of the safety review. The purpose of the
PSA is to supplement the deterministic assessment of the
plant’s safety status, identify potential improvements to
the safety concept and, in this way, check that the safety
design is balanced. In addition to internal and external
events in commercial operation, the Level 1 PSA also
covered events in the shutdown state and fires. The
frequencies of hazard conditions and core damage states
determined by the PSA are well below the frequencies
recommended by the International Atomic Energy Agency
(IAEA) for new plants.
The overall finding of the Safety Review shows that the
defence-in-depth and barrier concept provides a high level
of plant safety. No safety-relevant deficiencies or noncompliances
were identified that could jeopardise the
control of design-basis accidents, and hence the safe
operation of KWG.
Alongside the Level 1 Probabilistic Safety Analysis
conducted as part of the safety review, a Level 2 PSA was
carried out in accordance with the relevant PSA guidelines.
This included the consideration and probabilistic
quantification of extremely rare sequences of events
with postulated core meltdown and releases to the
surroundings. This was submitted in 2012. Amongst other
things, the calculations confirmed the high robustness of
the reactor containment. The value determined for the
frequency of large early releases is still approximately
three orders of magnitude below the value determined in
the Level 1 PSA for core damage frequency.
| Inside the turbine building. The turbine set has generated a cumulative 400 billion kilowatt
hours of electricity. (Photo: Bernhard Ludewig)
Retrofits and plant upgrades
As a pre-convoy pressurised water reactor, KWG already
has a basic design characterised by high robustness and
safety reserves. Over its years of operation, numerous
retrofits and improvements have been carried out but
these were not done to remedy deficiencies to prevent
damage but rather to extend the existing safety concept in
the sense of protecting against beyond-design-basis risks.
These included the retrofitting of a particulate and iodine
filter in the system for filtered pressure relief of the reactor
containment and measures for secondary-side bleed and
feed, the 3rd network feed, measures for primary-side
bleed and feed, retrofitting of passive autocatalytic
recombiners and installation of the sampling system from
the reactor containment.
Based on the lessons learnt from the accident in the
Japanese Fukushima Daiichi nuclear power plant, further
safety-related plant improvements were planned and
implemented. Once again, these were not done to remedy
deficiencies in the plant but rather to provide additional
risk prevention measures.
Alongside the safety-related enhancements, measures
were also taken to improve performance over the years.
Measurements taken at the time of commissioning showed
reserve capacity in the essential thermohydraulic parameters,
so that, following approval from the nuclear supervisory
authority, it was possible to increase the plant's
thermal capacity from 3,765 MW, as initially installed on
commissioning in 1984 , to 3,850 MW in 1990 and then to
3,900 MW in 1999. As part of the measures to increase
thermal capacity, work was also done to improve efficiency
of the turbines. Since then, the nuclear power plant has
had a gross nominal capacity of 1,430 MW at a thermal
reactor power of 3,900 MW.
With all these technical improvements, statutory maintenance
and responsible plant operation, the nuclear
power plant is as safe and reliable today as it was on day
one and moreover, more powerful than when it was first
commissioned.
Specialist and simulation training
Well qualified and regularly trained power plant personnel
are an essential prerequisite for the safe and successful
operation of KWG – not least because of the legal
requirements. Notably, in addition to the necessary
professional qualifications, e.g. as a skilled tradesman,
engineer or physicist, these impose further theoretical and
Feature
The World’s First Power Plant to Produce 400 Billion Kilowatt Hours ı Matthias Domnick, Sebastian von Gehlen, Stephan Kunze, Gerald Schäufele, Dietmar Schütze and Ralf Südfeld
atw Vol. 66 (2021) | Issue 2 ı March
| Loading of a Castor® cask at the Grohnde nuclear power plant.
(Photo: Bernhard Ludewig)
practical requirements for a person to be allowed to work
in the nuclear power plant or take on a position of
responsibility.
For staff employed in “other roles”, this includes graded
training courses in operational knowledge, occupational
safety, fire protection and radiation protection, depending
upon the level of responsibility of the role. For supervisory
shift personnel there are separate training schedules for
acquiring and maintaining specialist knowledge and a
professional exam in the presence of the authorities and
assessors before starting work as a reactor operator or
shift manager. Finally, the third group of personnel in
positions of responsibility (plant manager, sector or
departmental managers) has to submit a formal certificate
of com petence and their appointment must be approved by
the authorities.
As the last of the German plants, Grohnde NPP commissioned
its own nuclear power plant simulator at the
Essen Simulator Center in 2012. Before this, the shift
personnel were trained on an old simulator of the
Grafenrheinfeld reference plant. In retrospect, building
the new simulator has really paid dividends – not only
because it gave KWG access to the newest and best simulator
in Germany, but also because it brought about a
perceptible quality gain for the specialist personnel. This
unique training instrument was particularly valuable for
the last generation of trainees, who learned their skills up
until 2017 or re-qualified as shift manager representatives
in 2019.
In future, as the plant switches from commercial
operation to the dismantling phase, the focus will be on
health and safety aspects which include the so-called Tools
for Professional Behaviour. Not only will the number of
external contractors increase but there will simultaneously
be a decline in the number of employees who know their
way round a nuclear plant. This will require constant
training and (safety) briefings, which will continue to be
provided by KWG’s training department. On top of this, the
current pandemic is accelerating the development of
digital learning formats and online courses.
Radiation protection and discharge values
Right from the start of the design stage, great importance
was attached to radiation protection aspects, in order to
minimise radiation exposure associated with the plant.
Accordingly, structural radiation safety was taken into
account with concrete shielding and the spatial separation
of components.
These structural measures, the radiation protection
measures applied during planning and execution of maintenance
work and consistent personal dose monitoring
using the PADE dosimetry system serve to keep both
individual and collective doses of in-house and external
personnel at a low level.
Radiation protection measuring technology has been
continually replaced, improved and expanded over the
years, in order to comply with the current regulations and
the state of the art.
For example, the CeMoSys (Centralized Monitoring
System) monitors the measurement of personal contamination
using whole-body monitors directly at the exit
from the controlled area.
The nuclear power plant operates an environmental
monitoring laboratory, together with a measuring vehicle
with all the latest equipment, to carry out measuring
programmes in the surrounding area.
In terms of discharge values, radioactive discharges
from the nuclear power plant only account for a very small
percentage of the authorised limits. The calculated
maximum radiation dose to the public resulting from
discharges is well below 10 microsieverts (μSv) per
calendar year. This is well below the annual effective
radiation exposure in Germany, which ranges from 1 mSv
to 10 mSv a year, depending upon where people live, as
well as dietary and lifestyle factors.
International exchange of experience
Grohnde NPP has always advocated a successful exchange
of information, and not only in Germany. In addition to the
standardised exchange of information via WANO (World
Association of Nuclear Operators) and the IAEA (International
Atomic Energy Agency of the UN), it also
maintained relationships with nuclear power plants in
other countries.
Good examples of this are the collaboration with the
Spanish nuclear power plant Trillo and the Brazilian
nuclear power plant Angra 2. The KWU plants in those
locations are very similar to the pre-convoy design and
are of approximately the same age as Grohnde. These
commonalities form the basis for an effective exchange of
experience, especially in the area of nuclear safety,
operating experience, simulator usage, support during
commissioning and the management of ageing. Various
bilateral visits and meetings were held in these areas
within the framework of the VGB.
In addition to this, Grohnde NPP took part in the EU’s
so-called “twinning programme” at the start of the 1990s
with the aim of fostering cooperation between West
European and East European nuclear power plants. To this
end, an initial meeting was organised with representatives
from the Slovakian Bohunice nuclear power plant in
November 1991 and, in September 1993, a partnership
agreement was signed with the Ukrainian Jushno-Ukrainsk
nuclear power plant. Since then, reciprocal specialist
working visits have taken place at regular intervals. Despite
the EU ending the official twinning programme, Grohnde
continued the sometimes-biannual information exchange
with Bohunice and Jushno-Ukrainsk until 2010. During
this period, friendly links, which went far beyond purely
technical exchanges, were established between the sites.
As part of the BMU/GRS project on the “Evaluation and
utilisation of operating experience from events in East
FEATURE | OPERATION AND NEW BUILD 11
Feature
The World’s First Power Plant to Produce 400 Billion Kilowatt Hours ı Matthias Domnick, Sebastian von Gehlen, Stephan Kunze, Gerald Schäufele, Dietmar Schütze and Ralf Südfeld
atw Vol. 66 (2021) | Issue 2 ı March
FEATURE | OPERATION AND NEW BUILD 12
Imprint
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Official Journal of Kerntechnische Gesellschaft e. V. (KTG)
Publisher
INFORUM Verlags- und Verwaltungsgesellschaft mbH
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European nuclear power plants”, KWG repeatedly participated
with contributions to workshops both in Kiev and
also in Berlin and Cologne. These events were attended
in each case by up to 20 representatives from Russian
and Ukrainian supervisory authorities and from various
nuclear power plant sites.
In the last 10 years, Grohnde’s international activities
have been restricted to participating in WANO peer
reviews, workshops and technical support missions.
Dialogue with the public
In line with the phase-out of nuclear energy in Germany,
Grohnde NPP will cease commercial operation at the end
of this year. As a responsible nuclear power plant operator,
PreussenElektra GmbH is already planning the decommissioning
of the power plant and will dismantle it just as
prudently and carefully as it has operated it these last
40 years.
Grohnde NPP was and continues to be subject to public
scrutiny. In this regard, PreussenElektra’s transparent
information policy, which it still practices today, has
proven itself again and again. It is based on regular conversations
with political, industrial and media representatives
as well as on many different kinds of communication
materials for different occasions and target groups. This
communication strategy has enabled PreussenElektra to
maintain trust and, at the same time, strengthen the
reputation of its nuclear power plants. PreussenElektra
will continue to employ this tried and tested strategy
during the dismantling of all its sites.
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ISSN 1431-5254
Authors
Matthias Domnick
Sebastian von Gehlen
Stephan Kunze
Gerald Schäufele
Dietmar Schütze
Ralf Südfeld
Kernkraftwerk Grohnde
Kraftwerksgelände
31860 Emmerthal, Germany
info@preussenelektra.de
Feature
The World’s First Power Plant to Produce 400 Billion Kilowatt Hours ı Matthias Domnick, Sebastian von Gehlen, Stephan Kunze, Gerald Schäufele, Dietmar Schütze and Ralf Südfeld
atw Vol. 66 (2021) | Issue 2 ı March
“LTO Is Not Only Significantly Cheaper
Than Nuclear New Build Projects,
But Is Actually the Cheapest Option for
Power Generation Across the Board”
Interview with Mikhail Chudakov ı Deputy Director General and Head of the Department of
Nuclear Energy, International Atomic Energy Agency
13
INTERVIEW
In recent years nuclear power is being rediscovered
in many countries as a suitable path for climate
protection. At the same time some countries
are phasing out nuclear power and a reasonable
number of nuclear power plants is shut down
for economic reasons. From your point of
view, is nuclear power growing or decreasing
worldwide?
Nuclear power continues to expand. Climate change
mitigation and energy supply security are among the key
reasons why an increasing number of our Member States
are exploring the option of adding this clean, reliable and
sustainable source of power to their energy mix. Last year,
Belarus and the United Arab Emirates connected their
first power reactors to the grid, expanding the number
of countries that use nuclear power to 32. While some
western European countries are phasing out nuclear power
and it faces challenges in North America, Asia has become
the center of global nuclear power expansion. Currently,
52 power reactors comprising almost 56 GW(e) are under
construction in 19 countries; two-thirds in Asia
and four in so-called newcomer countries.
Around 30 newcomers are actively embarking
on or considering the introduction of nuclear
power. Overall, nuclear power has shown a
gradual growth trend since 2011, with
23.2 GW(e) of new capacity added by the
connection of new units to the grid or upgrades
to existing reactors. According the IAEA’s latest projections
to 2050, nuclear power will continue to play a key role
in the world’s low carbon energy mix, with capacity
increasing by more than 80 % to 715 GWe in our high case
projection. Technological innovations on the horizon, such
as small and medium sized or modular reactors (SMRs),
may be game changers in terms of offering countries more
affordable and flexible options.
Mikhail Chudakov
In some studies, e.g. by the OECD Nuclear Energy
Agency, long-term operation of nuclear power
plants is considered to be the most cost efficient
option for decarbonization in electricity generation.
What is the international experience with longterm
operation and how can this be supported?
An increasing number of Member States give high priority
to the long-term operation (LTO) of their existing nuclear
power plants (NPPs). For example, in the United States
several NPPs received license extensions to operate
between 60 and 80 years. A number of factors need to be
considered when deciding about LTO and while some of
them have to do with economics, all are grounded in the
premise of maintaining plant safety and security. NPP
Plant Life Management programmes have been successfully
implemented in several countries, and considerable
technical experience has been gained.
The IAEA develops guidelines to improve
Plant Life Management programmes
for LTO and delivers related training,
technical assistance, expert missions and
nuclear safety peer reviews to Member
States. Individual projects deal with
different aspects of nuclear power Plant
Life Management, with the aim of increasing the
capabilities of interested Member States in implementing
and maintaining sustainable nuclear power.
Nuclear power will
continue to play
a key role in the
world’s low carbon
energy mix.
Deputy Director General and Head of the Department of Nuclear Energy,
International Atomic Energy Agency
Mikhail Chudakov is the Deputy Director General and Head of the Department
of Nuclear Energy since February 2015. Until his appointment at the Agency,
Mr Chudakov served as the Director of the Moscow Centre of the World
Association of Nuclear Operators (WANO) since February 2007.
Prior to this, from 1995, he held a number of senior managerial positions in
Russia’s Rosenergoatom nuclear utility, including being appointed the Deputy
Director General of Rosenergoatom and Director of Bilibino Nuclear Power Plant
in April 1999. From 1993 to 1995, Mr Chudakov served as Adviser at WANO in
Moscow and in London. Between 1983 and 1993, he worked in a variety of roles at
the Kalinin Nuclear Power Plant, including Senior Reactor Operator. Mr Chudakov
holds a Ph.D. degree in nuclear engineering.
Climate change mitigation is urgent 1
and NPP LTO
represents a cost-effective opportunity to maintain low
carbon dispatchable capacity, thereby lowering the cost of
the clean energy transition. As the International Energy
Agency and the Nuclear Energy Agency said in their joint
1) IPCC, 2018: Global
Warming of 1.5°C.
Interview
“LTO Is Not Only Significantly Cheaper Than Nuclear New Build Projects, But Is Actually the Cheapest Option for Power Generation Across the Board” ı Mikhail Chudakov
atw Vol. 66 (2021) | Issue 2 ı March
INTERVIEW 14
report “Projected Costs of Generating Electricity, 2020
Edition”, NPP LTO is not only significantly cheaper than
nuclear new build projects, but is
actually the cheapest option for power
generation across the board. LTO helps
establish a bridge between operation of
the current fleet and arrival of new types
of reactors and contributes significantly
and immediately to climate change
mitigation. Indeed, Plant Life Management leading to LTO
has already delivered significant benefits to efforts to
reduce CO 2 emissions and air pollution while ensuring
security of electricity supply. Without ongoing LTO,
existing nuclear capacity will decline sharply before 2030,
particularly in Europe and North America. This could have
significant consequences for CO 2 emissions, air pollution
and the security of electricity supply.
This could have
significant
consequences for
CO 2 emissions.
On the flip side of the coin, does the IAEA support
countries phasing out nuclear power e. g. with
regard to the decommissioning of power plants?
Yes. The IAEA supports countries on the implementation
of all stages of the lifecycle of nuclear installations used
for peaceful purposes, including faci lity decommissioning
and associated spent fuel and
waste management at the end
of the lifecycle. Many of the
443 nuclear power reactors
currently in operation will
phase out of service over the
next few decades, in addition to
closures of some research reactors and nuclear fuel cycle
facilities, leading to signi ficant increases in the scale of
decommissioning projects being undertaken around the
world. The Agency is committed to supporting Member
States in imple menting these programmes, in addition to
supporting emerging nuclear power programmes, i.e. to
establish strategies for future decommissioning and to put
in place the necessary legal and institutional arrangements
to support future decommissioning.
We assist Member States in efforts to plan and
implement decommissioning projects through a range of
mechanisms, including development of safety standards
Many of the 443 nuclear power
reactors currently in operation
will phase out of service over the
next few decades
and Nuclear Energy Series publications and other
reports on technical and safety related aspects.
We also organize meetings of experts, collaborative
projects, scientific exchanges, training
courses and workshops. We have a dedicated
peer review service called ARTEMIS (Integrated
Review Service for Radioactive Waste and Spent
Fuel Management, Decommissioning and Remediation)
that supports countries in strengthening their work in
these areas; indeed, Germany hosted an ARTEMIS review
in 2019. And all these Agency activities are supported
by resources including an eLearning platform and the
International Decommissioning Network (IDN), which
provides a forum for interaction among experts who can
also share knowledge via a wiki-based information resource.
The Agency promotes the adoption of circular economy
principles for decommissioning and related waste
management considerations.
Currently, we are carrying out a major initiative to
catalogue and analyse the status of decommissioning
programmes worldwide, including challenges being faced
and experiences gained in addressing them. The Global
Status of Decommissioning project report, expected to
be published next year, will be an important resource
for those with policy responsibility for decommissioning
programmes as well as for other stakeholders interested
in the future management of liabilities from nuclear
activities.
For a substantial contribution of nuclear power to
mitigate climate change, new-build of power plants
is necessary, not least in emerging economies. How
does the IAEA support countries that are starting
the peaceful use of nuclear power?
The IAEA offers comprehensive support to its Member
States that are considering or embarking on new nuclear
power programmes, including guidance, advice, training
and peer review services. As I previously mentioned,
around 30 countries currently belong to this group, two of
which (Belarus and the UAE) recently achieved the major
milestone of connecting their first power reactors to the
grid after about a decade of working with the Agency in
developing the necessary infrastructure for nuclear power.
Two other newcomers, Bangladesh and Turkey, are
currently building their first plants. When we talk about
nuclear infrastructure, we mean things like establishing
competent institutions, nuclear regulatory and legal
frame work or human resources development, which
support a nuclear power programme
throughout its life cycle. The adherence to
international legal instruments, internationally
accepted nuclear safety standards,
security guidance and safeguards
requirements is also essential. Based on
the principles of these instruments, the
development of a nuclear programme and the intro duction
of nuclear power remain national responsibilities.
Experience shows that the time from the initial consideration
of the nuclear power option by a country to the
operation of its first nuclear power plant based on
evolutionary current designs is about 10 to 15 years.
During this period the IAEA Milestones Approach provides
countries with a sound and internationally accepted
methodology for developing their nuclear power programme
and create an enabling environment for the introduction
of nuclear power, helping them to understand and
prepare for the commitments and obligations associated
with a safe, secure and sustainable
civil nuclear programme. The IAEA
also offers training and expert advice,
as well as peer review services
like the Integrated Nuclear Infrastructure
Review (INIR) for each
phase of the programme, which assesses
the status of national infrastructure for the introduction
of nuclear power; since INIR’s introduction in
2009, 30 such reviews have been conducted in 21 Member
States. The IAEA also offers peer reviews and advisory
services in other critical areas like the Site and External
Design Events (SEED) review in the field of site selection
and external events, IRRS in the field of nuclear safety,
IPPAS in the field of nuclear security, ISSAS in the field of
safeguards, EPREV in the field of emergency preparedness
and response and pre-OSART in the field of readiness for
operation. Drawing on such reviews, the IAEA develops
country-specific integrated work plans to assist newcomers
in addressing gaps in their nuclear infrastructure and
conducts follow-up reviews to track their progress. We also
provide across-the-board training for countries to make
informed commitments about nuclear power and to build
their capacities. Between 2016 and 2019, the IAEA
The time from the initial
consideration of the
nuclear power option
is about 10 to 15 years.
Interview
“LTO Is Not Only Significantly Cheaper Than Nuclear New Build Projects, But Is Actually the Cheapest Option for Power Generation Across the Board” ı Mikhail Chudakov
atw Vol. 66 (2021) | Issue 2 ı March
pro vided direct support to 50 Member States on all these
issues, training 1250 participants through courses, scientific
visits, workshops and fellowships. 17 institutions in
12 Member States hosted these events.
It has become increasingly difficult to finance newbuild
nuclear power plants in some areas despite the
availability of enormous amounts of investment
capital. Are there international best practice examples
for supporting the financing of nuclear new build?
Financial institutions consider nuclear projects challenging
to finance because of the large outlay of capital required,
relative long construction times and overall construction
costs associated with some of the First Of A Kind projects.
These uncertainties decrease with Nth Of A Kind projects.
Recent experience shows that construction costs can
be effectively contained through multiunit construction
programmes. These allow plant
developers, vendors, work crews
and regulators to gain experience
over time. The continuous nuclear
construction programme in China
or Russia demonstrate how this
experience helps deliver projects on budget and on time.
South Korea, which leveraged standardized plant design
to build out its fleet, is another example.
A key element in financing nuclear power is managing
and sharing the risks associated with nuclear projects.
Governments have a major role to play here. Historically,
NPPs have relied more often on governmental financing
than on corporate financing where the investment is
financed from the company’s balance sheet.
One case study in financing nuclear projects is the
Finnish Mankala model, a form of corporate financing
by several parties such as energy intensive industries,
municipalities and energy wholesalers. It is not specific
to nuclear, and it has been used also to finance capitalintensive
energy projects.
Other mechanisms such as Power Purchase Agreements
(PPA), or Contracts for Differences (CfD) are a key factor
for fostering investments in nuclear projects by providing
certainties on future revenues.
In recent years the nexus between financial
regulation and climate policy came into focus, using
the former to foster the latter. From the IAEA perspective,
how should nuclear power be treated in
financial regulation with regard to climate change?
Government policies to support low carbon electricity
generation have materialized as direct subsidies, feed-in
tariffs, quota obligations and energy tax exemptions.
Carbon pricing is one of the measures widely used, and it
can make all low carbon sources more competitive in the
Investments in low
carbon technologies can
be key to the success
of the energy transition.
Recent experience shows
that construction costs can
be effectively contained.
long term.
Thus, it is important
for the success of the
global transition to low
carbon energy systems
and to limit the impact of
climate change, that
nuclear power is recognized as a clean and sustainable
technology, meeting Environmental, Social and Governance
(ESG) criteria. It should therefore be eligible for
“green” (or “sustainable”) financing.
In the context of the post-COVID-19 recovery, investments
in low carbon technologies can be key to the success
of the energy transition and the economic recovery. In that
respect, investments in nuclear projects, including LTO of
existing nuclear power plants, can be beneficial in several
respects. LTO investments lead to the lowest electricity
production costs according to the IEA and are critical to get
the energy transition back on track.
In the early years of nuclear power there was much
hope for close international cooperation of the
peaceful use of nuclear energy. Is more support and
commitment desirable to proceed and extend this
objective and what has to be done or is desirable?
Enhanced international cooperation is essential for the
full potential of nuclear energy to be realized. And that
potential is truly impressive: nuclear power is a highly
reliable source of 24/7, low carbon electricity that already
provides 10 % of the world’s electricity and can be quickly
scaled up to meet growing energy needs and ensure energy
security for decades to come. But getting to
where we need to be means working together
for our mutual benefit.
When we talk about comprehensive decarbonization,
it must be acknowledged that this is
a task requiring a truly global effort. Establishing
a stable yet flexible low carbon energy supply is vital to
achieving the Sustainable Development Goals, and there is
a growing consensus that nuclear power must be a central
component of these efforts.
To be sure, there has been, and continues to be, significant
cooperation in nuclear power. From knowledge sharing
to technical cooperation to financing mechanisms, nuclear
power programmes thrive when the considerable wealth of
global expertise in nuclear energy
is effectively leveraged. We at the
IAEA feel a sense of pride but also
great responsibility in our role as
the global forum for cooperation
on the peaceful uses of nuclear
energy. Our work takes on many
forms. The Agency plays a fundamental role in the application
of nuclear safeguards worldwide. But we also develop
the internationally accepted standards for nuclear safety
and act as a catalyst for innovation in nuclear power through
our support to Member States including technical guidance
such as the Nuclear Energy Series publications that my
Department of Nuclear Energy produces, as well as technical
meetings, international conferences, trainings, peer review
services and our many professional networks.
All this international support and cooperation is vital to
the present and future of nuclear power. Indeed, if we are
to achieve our climate and sustainable development goals,
we would have an opportunity to further expand and build
on these already robust collaborative efforts to facilitate
the clean energy transition our world needs.
Interviewer
Nicolas Wendler
Head of Media Relations and Political Affairs
KernD (Kerntechnik Deutschland e.V.)
nicolas.wendler@kernd.de
All this international
support and cooperation
is vital to the present and
future of nuclear power.
INTERVIEW 15
Interview
“LTO Is Not Only Significantly Cheaper Than Nuclear New Build Projects, But Is Actually the Cheapest Option for Power Generation Across the Board” ı Mikhail Chudakov
atw Vol. 66 (2021) | Issue 2 ı March
16
SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER
Quo Vadis, Grid Stability?
Challenges Increase as Generation Portfolio Changes
Kai Kosowski and Frank Diercks
Introduction The power generation portfolio in the German high voltage transmission and distribution system has
been constantly changing since 2011. After several decades with relatively constant segmentation into base-, mediumand
peak-load and a power plant park designed accordingly for these purposes, significant changes have occurred in the
last 10 years. As an important result of the so-called Energiewende 1 , starting in 2011 with the shutdown of the first
German nuclear power plants (NPP) after the reactor accident in Fukushima, the last NPPs will go eventually offline by
the end of 2022.
The Coal Phase-Out Act of August 8 th , 2020, a far-reaching
edit with significance for the energy industry in Germany,
requires the shutdown of all coal-fired power plants by
2038 at the latest.
From this point in time at the latest, there will be no
large, inductive power plants for generating base load in
the German power plant park.
Basic mechanism
for a stable electrical power grid
The electrical power grid is stable when generation and
consumption are balanced within the overall system.
Excess electrical energy cannot be stored directly, and the
grid itself cannot store any energy. Generated electricity
needs to be consumed instantaneously. Indirect storage in
pumped hydroelectric energy storage, battery storage
systems, or by other storage technology are possible in
principle, but are only implemented to a limited extent in
today’s electricity supply system [1].
The biggest Battery Energy Storage System (BESS) in
central Europe is in Jardelund/Germany close to the
German offshore wind farms in the North Sea. The
BESS Jardelund has a power of 48 MW, fully charged,
and provides 50 MWh of energy before needing to be
recharged [2]. In comparison to the power class of a
conventional 1100 MW coal-fired power plant or even a
1300 MW NPP, the capacity of BESS Jardelund would
be exhausted after 2 min 44 sec of the coal-fired power
plant respectively after 2 min 18 sec of the NPP full load
operating time.
In principle, BESS could make a contribution to storing
energy resulting from excess generation by renewables. A
review of energy storage technologies in cooperation with
wind farms is given by Rabiej [3]. Many publications are
produced around the globe which investigate the potential
contribution of BESS. Those BESS should be used to
enhance the stability of the power grid, ensuring system
reliability, increased grid flexibility, and to make further
expansion of renewable energy possible – all in regard to
the changing electricity market’s growing influence of
renewables [2], [4], [5], [6]. The application of BESS is
promising, but still at a deployment level in terms of
maturity, power spectrum and recharge/discharge capacity
[7], [8].
A brief assessment of the power spectrum illustrates the
current situation of BESS: the annual total net generation
in Germany in 2018 was 592.3 TWh [9], which means an
average net generation of about 1.6 TWh on a daily basis is
required, orders of magnitudes greater than the storage
capacity of the largest European BESS Jardelund. The
prognoses of storage requirements in Germany vary widely
from only 2 8 TWh up to 61 TWh in [10], 16 TWh in [11] 3 ,
and 22 TWh in [12] or even 80 TWh in [13] depending on
the deployment level of renewables. It is questionable if
studies offering lower capacity prognoses have considered
that weather phenomena like the Dunkelflaute 4
will
never occur with fully charged batteries, which would
additionally increase required demand.
Cost estimates are given in [17] referenced in [16] and
can be projected to 750 Euro per kWh capacity in 2020, to
300 Euro per kWh in 2030 and to 150 Euro per kWh in
2050 due to economies of scale. With today’s prices, the
commission of the smallest storage capacity (8 TWh)
would cost 6 trillion (1012) Euro, operational costs
excluded. These enormous costs must be additionally
associated with the comparably short lifetime of BESS,
approximately 10 years (see i.e. [18]).
Currently, the only mature, fully commercialized
energy storage technology within a seriously considered
power is pumped hydroelectric energy storage. Disadvantages
in comparison to other generating units is, that
they turn to consumers when it is necessary to recharge
their upper located water reservoirs; in contrast, they have
no fuel costs except the power needed for pumping mode.
Thus, economical aspects come into play regarding
variable costs.
Particularly in Germany with its north-south divide of
coast and mountains, pumped hydroelectric energy
storages appear in the south by reason of necessary
geodetical height, whereas wind farms are in the flat
northern countryside, or offshore, along the coast, with
enhanced upstream flow conditions due to the lack of
mountainous “obstacles.”
In addition, there is another relevant north-south
divide in Germany 5 in terms of high industrialization in the
south (and west) and the northern regions, generally
characterized as more rural and agricultural. Thus, in the
south, pumped hydroelectric energy storage predominates
1 German energy transition.
2 Even the smallest prognose 8 TWh storage capacity means unbelievable 160,000 times the BESS Jardelund.
3 Authors of [11] are assigned to the affirmatives of the energy transition. It is noteworthy that they deny explicitly the statements made in [12]. The smaller numbers
were obtained since curtailment of renewables has also been considered but not in [12]. In that case, the comparison is hampered.
4 Dunkelflaute is a compound German word combining “Dunkelheit” (darkness) and “Windflaute” (little wind). It is used in the context of energy sector and describes
periods when solar and wind power generation is very low. In Germany a Dunkelflaute may last about 2 weeks, particularly in winter season. Reference is given i.e. to
[14] and [15].
5 There are a lot of north-south divides in Germany but that is beside the topic.
Serial | Major Trends in Energy Policy and Nuclear Power
Quo Vadis, Grid Stability? Challenges Increase as Generation Portfolio Changes ı Kai Kosowski and Frank Diercks
atw Vol. 66 (2021) | Issue 2 ı March
| Figure 1
Covering daily demand before appearance of renewables (left), coping with renewables with leftover demand [19].
near huge industrial consumers. In the north, wind farms
(particularly those located offshore) tend to be further
from load centers.
In today’s overall climate of expansion of energy storage
systems, the introductory statement remains valid: generated
electricity needs to be consumed instantaneously.
From a technical point of view, the power balance is
maintained when the grid frequency is kept within a very
narrow range around the setpoint of 50 Hz. If consumption
exceeds generation, energy is withdrawn from the rotating
generators of the power plants, and consequently grid
frequency drops, with the obverse true if generation
exceeds consumption. Control systems must have access
to controllable power generating units or controllable
consumption devices in order to be able to return the
current imbalance in a targeted manner [1].
The scale-pan of consumption is characterized by the
day-to-day constant consumer load profile for ordinary
working or weekend days with seasonal and predictable
long-term fluctuations over decades. At times, special
events take place and characterize the consumer load
profile differently to the ordinary day (viz., the “roast
goose-peak” or the “church attendance-sink” at Christmas
or the finale of a soccer game with German participation).
These events are singular, predictable, and therefore easy
to handle for the control systems in charge of the operational
readiness of additional generating units, if available
in the system.
The scale-pan of power generation tends to follow suit
regarding the consumer energy demand profile illustrated
in Figure 1. In previous decades, prior to the growth of
renewable energy, (left-hand side of Figure 1), the power
supply was divided into the three categories: 24 h night
and day base load, load following during daytime, and
peak load for a short daily period 6 .
The electrical power generation system consists of a
range of units utilizing varying fuel sources for electrical
generation, up to and including auxiliary power for
pumped hydroelectric energy storage used for recharging.
In balancing generation and demand, it is customary to
operate the generating units in that sequence to minimize
overall operating costs. Therefore, the generating units
with the lowest marginal production costs are operated
at full load as long as possible to cover the baseload.
Generating units with higher marginal production costs
are operated with changing electrical output to match generation
with residual demand beyond baseload. The generating
units with the highest marginal production costs
are only operated during day peaks, with pumped
hydroelectric energy storage having recharged upper
water reservoirs during low price base load periods. This
cost-optimal employment sequence of the generating units
is known as merit order.
All available generating units are sorted in ascending
order according to calculated marginal costs, and plotted
against the cumulative installed electrical power, see
Figure 2. Current demand indicates the generating unit
which must be employed. It then becomes the marginal
power plant with the highest current costs. The left panel
in Figure 2 shows sorted generating units covering
SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 17
| Figure 2
Principle of merit order in former times without renewables (left) and with must-run renewables (adapted from [21]).
6 For example, at the early evening homecoming from work but with still running and power consuming industry.
Serial | Major Trends in Energy Policy and Nuclear Power
Quo Vadis, Grid Stability? Challenges Increase as Generation Portfolio Changes ı Kai Kosowski and Frank Diercks
atw Vol. 66 (2021) | Issue 2 ı March
SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 18
| Figure 3
Dynamic hierarchy of load-frequency control processes [26], [27].
demand with the market-clearing price of the marginal
power plant. The units indicated to the right of the current
demand are not requested, since demand is already
covered, and they cannot provide power for price. Generating
units with marginal production costs that are lower
than the market-clearing price benefit from earning
incremental revenues, which contribute to their fixed
costs. The marginal power plant is only able to cover its
variable operating and maintenance costs [20].
With the deployment of renewable technologies, the
merit order of generating units is no longer driven by
economic aspects. The legal framework for the expansion
of renewable energies in Germany is found in the Renewable
Energy Sources Act [22]. On one hand, it regulates
the priority supply of electricity from renewable sources
into the power grid. On the other, the law determines a
guaranteed feed-in remuneration for renewables which
elevates them to a special status. Whenever wind is
blowing or the sun is shining, the operators can feed into
the power grid, without caring whether it is needed. The
status of renewables can be described as “must-run” 7 in
the merit order.
The “must-run” renewables with marginal costs near
zero are sorted at the beginning of the ascending order and
shift the whole conventional fleet of generating units to the
right side of the diagram (right panel in Figure 2). Due to
the reduced residual demand covered by the conventional
fleet (Figure 1, right-hand side), the threshold for the last
generating unit to be requested will be a cheaper one than
in the previous example. The previous marginal power
plant, suffering from low capacity, is forced out of the
market, with the units represented on the right coming
into play with increasing rarity. With fewer operational
hours of the units forced out, fuel costs per MWh rise,
which make requests for reemergence into the market even
more difficult.
Ultimately, it is always a matter of costs, and, finally, if
one may ruminate with a soupçon of bemusement, a
matter of soothing the green conscience. At first glance,
nature seems to provide that much-vaunted win-win
situation: the sun is shining, the wind whips round the
blades of windmills, and costs are nil. Current demand
should thus dictate that expensive gas-fired power
generation be forced out by renewables, which then engenders
a reduction of wholesale power prices, which in
turn has a negative impact on the profitability of conventional
power plants [23]. Thus, the cheaper generating
units on the left-hand side must content themselves with
lower incremental revenues. This is known as the merit order
effect of renewables. The matter of minimizing costs
would seemingly appear to be settled. Furthermore, as fossil-fired
generating units are forced out of the market, societal
awareness of the environment, specifically of sustainable
concepts fomented to combat climate change, and governmental
strategies designed to reduce carbon emissions,
are on the ascent. The matter of the soothing of the green
conscience might also seem to be covered, but in truth this
mollification is easier pontificated than achieved.
The main issue that counteracts the win-win-consideration
is that renewables have largely intermittent output
with limited predictability, an result not correlated with
variations in electricity demand [19], if so, it is pure coincidence.
To posit these realities within the cant of pragmatic
resignation, consider this idiom: “When wind is there, it’s
there:” [24]. Rather than steadying supply, renewables
disturb efforts to maintain grid frequency stability due to
their unreliability – forecast deviations preclude the energy
from being dispatched. The supply curve increases and
decreases depending upon climatological conditions. The
greater the penetration of renewables, the larger the shift
in the supply curve, coupled with a rise in price volatility
[20].
One of the core tasks of Transmission System Operators
(TSO) is to ensure system stability. TSOs fulfill this task
through ancillary services, including, amongst others, the
maintenance of power balance and frequency through the
provision and application of three different kinds of
balancing reserve in the continental European transmission
network [9].
The primary control reserve 8 immediately stabilizes the
frequency after a disturbance within 30 seconds at a
steady-state value by joint action within the entire
continental European synchronous area. It is completely
automated and delegated to the large-scale power plants
[25]. The subsequent secondary control reserve 9 is
triggered by the disturbed load frequency area and returns
the frequency towards its set point within 5 minutes. The
primary control reserve remains activated until it is fully
replaced by the secondary reserve in a ramp-wise characteristic
so that the work capability of the primary reserve
control is restored again for the next possible disturbance.
Additionally, the secondary reserve is replaced and/or
supported by the tertiary control reserve (or minute
reserve) 10 within fifteen minutes in a ramp form [26].
The dynamic hierarchy of the balancing reserve is
illustrated in Figure 3. In recent years, with growing
deployment and penetration of must-run renewables
linked with reduced inertia, grid maintenance complexity
has increased enormously.
Role of the nuclear power in grid stability
NPPs belong to generating units with the lowest marginal
production costs. Thus, following the rules of merit order,
they are operated at full load when possible. The public
7 The term “must-run” is not yet correct. The privilege has been abridged by an amendment of the Renewable Energy Sources Act. More information will be provided in
a further chapter about misalignments.
8 Also called Frequency Containment Process (FCR).
9 Also called Frequency Restoration Process (FRR).
10 Also called Reserve Replacement Process (RR).
Serial | Major Trends in Energy Policy and Nuclear Power
Quo Vadis, Grid Stability? Challenges Increase as Generation Portfolio Changes ı Kai Kosowski and Frank Diercks
atw Vol. 66 (2021) | Issue 2 ı March
| Figure 4
Comparison of load change rates of conventional generating units (adapted from [33] with data from [32] and [34]).
perception of NPPs suggests that they are only made for
baseload operations and are too inflexible for any kind of
load change. Such pronouncements were aired not just by
anti-nuclear organizations but also by the German Federal
Environment Ministry, which ascertained that NPPs are
the most inflexible facilities within the traditional power
plant fleet due to their inflexibility and frequent starts and
shutdowns, and if possible should be avoided for safety
reasons [28] (in [29]). During discussions in the late
2000s regarding lifetime extensions of NPPs, sloganeers
suggested that the plants might clog the power grid and
jeopardize the development of renewable energies.
Among the curious myths surrounding nuclear energy
that have been met with dismay and incomprehension by
experts, allegations of inflexibility earn a special, Stygian
ranking, due to the simple fact that the exact opposite is
true [30].
Of course, due to low marginal production costs, NPPs
have reliably contributed to base load demand over
the decades since their introduction. Due to market
mechanisms, there was never an economic need to throttle
the power of the NPPs if more expensive generating units
remained in operation. A persistent canard suggests that
due to their supposed inability to manage load changes –
not because of their low-cost operational status – NPPs ran
only in base load. This supposition proved apparently
sturdy, however, and the perception that NPPs always
operated at full power – or were only able to do so – became
entrenched. Even published power chart illustrations
mirrored the conjecture, that NPP “always” or rather “only
can” operate at full power.
In fact, German NPPs are the most flexible generating
units in the portfolio, and were particularly able to
demonstrate that capability in practice. In the case of
renewables’ high feed-in, it more frequently occurs that a
huge part of current demand is covered by renewable
sources, with one of the NPPs then becoming the marginal
power plant, and all fossil-fired plants located on the righthand
side of the NPPs in the merit order diagram (Figure 1
right-hand side) not being employed at that moment –
always a snapshot – and are thus forced out of the market.
In that case, even the NPPs must throttle power generation.
Due to the geographical imbalance, NPPs in the north are
particularly affected to conduct load following operations.
Their high flexibility remains an open question. Due to
the oil crisis and its tremendous dependency on foreign
energy resources, Chancellor Willy Brandt’s government
launched the first German energy program in 1973. Among
other issues, the intention of the initiative was to increase
the capacity of NPPs up to at least 40 GW, and preferably up
to 50 GW, through 1985 [31]. Regarding the ascending
order of generating units in the merit order diagram, it
would have led to a very broad interpretation of the NPP
category. In the forward-looking 1985 scenario, NPPs would
have undertaken duties beyond baseload operation, including
load following operations. The design of NPPs already
had to be adapted for that purpose in their planning phases
to have the flexibility to meet the requirements of the designated
scenarios with large shares of nuclear power. In the
end, the commission of 50 GW installed capacity was not
realized, but constructed NPPs have been given the capability
of flexible operation by design (and not by retrofit).
The load change rate over time is shown in Figure 4 for
various thermal generating units. The NPPs have the
largest load change rate, paired with the biggest power
generation per single unit. Load following down to 50 %
can be conducted in NPPs with a gradient of 5 % of nominal
power per minute, down to 80 % (but not below) even with
a gradient of 10 % per minute; thus, with an enormous
140 MW/min. The operating manuals 11 of the KWU-type
PWR, which contain all operational and safety-related
instructions, indicate even higher performance ranges.
Load changes of up to 80 % of nominal power – thus, down
to 20 % – are permitted (published e.g. in [32]). This
strong load reduction comes at the expense of the load
change rate. It decreases to a gradient of 3 % of nominal
power per minute (42 MW/min), which is, however, still
competitive with the fossil-fired power plants.
SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 19
11 Not publicly accessible.
Serial | Major Trends in Energy Policy and Nuclear Power
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atw Vol. 66 (2021) | Issue 2 ı March
SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 20
| Figure 5
Partial load diagram of a German PWR (simplified) [38].
The fastest non-nuclear units are a small number of
new fossil-fired power plants, which were designed in
consideration of the increased demands of flexibility.
With changing markets and the prioritized, fluctuating
feed-in of renewables, efforts were made to enhance the
design of coal-fired plants to more suitably meet load
following requirements. Enhancements were imple mented
to further lower minimum permissible power, but not
expressly to increase the load change rate [35]. Factors
limiting an increase of load change rate in coal-fired power
plants include combustion performance, the mass flow of
fossil fuel through the coal mill, and particularly the
thermal stress of thick-walled components. Fluctuations
of pressure and vapor temperature due to declining
control accuracy also play roles as limiting factors [36].
The best per forming units reach a gradient of around
40 MW/min 12 .
The load change in NPPs is not limited to a mass flow of
fuel. Due to the high energy density of a nuclear core, a
smooth insertion or withdrawal of control rods leads to a
strong load change. The thermal stress of components as
limiting factors for the load change rate is not that
significant in NPPs as well. Regarding secondary circuit,
water-moderated NPPs do not superheat steam to obtain
high efficiency, as do fossil-fired plants 13 . The steam
generation in water-moderated NPPs is limited to the
saturated vapor line. Temperature differences are not as
high as in power plants with superheating capabilities.
One of the hallmarks of KWU-type pressurized water
reactors (PWR) is the constant average coolant temperature
over a wide range of their partial load reactor power
levels, resulting in minimal changes of pressurizer level.
| Figure 6
Real example of power control in practice on first week of October 2018 (adapted from [27]).
Figure 5 schematically depicts the partial load diagram of
a KWU-type PWR. It shows the temperature of the primary
coolant at inlet / outlet of the reactor pressure vessel, as
well as the average cooling temperature, depending on the
reactor’s power [37], [38]. Particularly in the upper power
range, under special focus for load following operation,
the average coolant temperature remains constant more
than half of the entire power range.
This enables quick, subtle load changes with precise
control behavior and minimal thermal stress and fatigue
on the primary circuit components [29], [30]. In regard to
safety, all physical reactor parameters such as neutron flux,
power density and power distribution are kept under
constant double surveillance by the reactor limitation
systems and the reactor protection system.
With the capability of fast and nimble load changes,
NPPs fulfill the technical requirements to provide varying
levels of balancing energy as requested by the TSO [29],
[39] illustrated in Figure 3. The NPP can be operated
automatically by controlling the power set point of the
generator. The primary side follows suit with the demand
of the secondary side and regulates the average coolant
temperature. Figure 6 shows the power control in practice
due to fluctuations of solar and wind power.
PWRs have the ability to automatically counteract
changes in coolant temperature resulting, for example,
from a requested power ramp on the generator side, by
changing the reactor power accordingly, see Figure 7. This
feedback behavior is adjusted by means of coolant
temperature control, based on the neutron-kinetic effect
of the negative coolant temperature coefficient of
reactivity Γ K .
A requested reduction of generator power leads to a
throttling of turbine admission valves and an increase of
upstream main steam pressure. Due to thermal coupling of
the steam generators, particularly with the primary’s cold
legs, an increase of coolant temperature results. In short,
as the turbine demands less power than is generated
by the reactor, the primary circuit becomes temporarily
warmer. With the rising temperature of the coolant,
density decreases, and reactivity is consumed. Via neutronkinetics,
the neutron flux j decreases and hence reactor
power as well. A decrease of reactor power releases positive
reactivity via Doppler effect by a reduction of the average
fuel temperature, and by an increase of fuel density owing
to reduced average fuel temperature. Both effects are
subsumed in the power coefficient of reactivity Γ P , which
always automatically counteracts any change of reactor
power ∆P. It is part of the inherent safety concept of nuclear
reactor design. In this case, the gain in reactivity related to
a decreased demand in power balances the reactivity
consumed by the rising average coolant temperature.
Decreasing reactor power has a feedback on heat
transfer, which counteracts the indirect increase of coolant
temperature (returning orange arrow) caused by the
throttling of turbine valves.
For a requested increase of generator power, the
antipodal result occurs. An excess of power prevails on the
turbine side; more power is extracted from the steam
generator towards the secondary side, and the primary
circuit becomes temporarily sub-cooled. With lower
coolant temperature, reactivity is gained, and reactor
power increases again. The heat transfer increases and
12 One must keep in mind that the coal-fired plants are often build as multi units at one site.
13 Some of the coal-fired plants even operate with supercritical water.
Serial | Major Trends in Energy Policy and Nuclear Power
Quo Vadis, Grid Stability? Challenges Increase as Generation Portfolio Changes ı Kai Kosowski and Frank Diercks
atw Vol. 66 (2021) | Issue 2 ı March
balances the drop of coolant temperature. Part of the
gained reactivity is compensated in this case by the
negative contribution of power reactivity feedback. An
increase of power consumes reactivity (Doppler effect and
fuel density).
The requested change of the generator power set point
is initially buffered by the reactivity feedback of changing
coolant temperature. If the coolant temperature deviates
from its dead band (in both directions), it is then
transferred to the control rod position controller.
KWU-type PWRs have control rods that are functionally
divided into two control rod banks – the L and D banks.
The majority of control rods are assigned to the L bank,
which remains at a high position during power operation
and preserves the shutdown margin, an important
parameter for safety [38]. The four D banks, each
comprising four control rods, are used for regulating
integral reactor power. They are weaker in comparison to
those comprising the L bank and do not markedly disturb
power distribution [40]. Depending on the control rod
maneuvering concept, one or more of the D banks are
partially inserted or withdrawn, which accordingly
elicit prompt feedback on reactor power so that coolant
temperature returns smoothly to its set point. Thus, during
partial load operation, the automatic movements of
control rod banks provide the method of choice to ensure a
balance of reactivity despite load ramps.
For a considerably lengthier partial load operation –
and only in that case – the control rod banks tend to be
withdrawn again to avoid both a stronger peaking of the
axial power distribution and a burn-up imbalance between
bottom and top core regions. For that purpose, the control
rod bank controller regulates the reactivity balance by
feeding boron into the coolant while the bank is slowly
withdrawn. The gained reactivity from the removal of
control rods 14 is compensated by an increase of the concentration
of the neutron absorber. The reactor core will be
operated in partial load with fully withdrawn control rods,
but with increased boron concentration 15 . In case of a
positive load change, deionized water will be fed into the
coolant to decrease the boron concentration, while control
rod banks are partially inserted. The increase or dilution of
boron concentration is quite slow, and this operation mode
significantly slows the possible load change rate of the
NPPs. Aspects of Xenon build-up also come into play.
Changes of boron concentration are not usually carried out
if the NPP is requested by the TSO for short-term load
following operation.
| Figure 7
Feedback of reactor power on requested load reduction (for a requested increase invert all signs).
In the case of other conventional generation technologies,
a steady decline in the capacities connected to the
grid can also be observed, due to market forces under the
rules of merit order making operation too expensive.
Should this occur, the costs of power generation might not
be able to be covered, leading to a vicious economic circle
prior to a new request. Since the marginal costs of production
per MWh will rise with reduced time of operation,
see Figure 8, the affected power plant will be ranked
farther on right side in the ascending merit order, see
Figure 2. In the case of the highly efficient but expensive
combined cycle gas turbine (CCGT) Irsching Unit 5, which
was commissioned in 2010, its operating hours have fallen
tremendously to a level of economic inefficiency which
prompted the utility to apply for shutdown. Conversely,
decline in capacity can be observed due to stipulations in
the recently enacted German regulations for the phase-out
from the coal-fired power generation by the end of 2038
[41].
The import of electrical energy from neighboring
countries in the north and Scandinavia with the simultaneous
export of electrical energy to neighboring
countries in the south creates a burden for the trans mission
network. This north-south divide of international
SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 21
Development and progression of the energy
transition and its misalignments
The German Energy Transition with public incentives for
more investments is leading to a steadily growing share of
renewable energy in the German electricity mix. But,
particularly regarding the installed capacity from wind
turbines on land and sea, it can be observed that there is
still a clear geographical imbalance between the locations
of the prevalent, lower power plants in northern Germany
and the consumption centers in the south. In addition
to the expansion of renewable energies, the nuclear phaseout
in Germany is also progressing, thus, huge conventional
generating units with high capabilities of load
following operation will exit the market by end of 2022.
| Figure 8
Marginal costs of specific power generation versus operating hours [21].
Operating hours CCGT Irsching Unit 5 (commissioned 2010) [42].
14 In difference to the illustration in figure 7, the reactivity contribution based on control rod movement is +Δρ CR because of their removal -Δs.
15 The reactivity contribution of the control rods Δρ CR is replaced by the reactivity contribution based on boron concentration Δρ C .
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SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 22
Reduction of power generation
Top ranking in 2018
| Table 1
Top ranking units 2018 for negative redispatch measures.
| Table 2
Top ranking units 2018 for positive redispatch measures.
Negative redispatch
energy
Full load hour/
day equivalent
1. Wilhelmshaven (Engie) 866 GWh 1185 h / 49.4 d
2. Jänschwalde 658 GWh 219 h / 9.1 d
3. Schwarze Pumpe 635 GWh 397 h / 16.5 d
4. Boxberg 606 GWh 236 h / 9.8 d
5. Wilhelmshaven (Uniper) 377 GWh 498 h / 20.8 d
.. .. .. ..
8 Moorburg 166 GWh 166 h / 6.9 d
Raise of power generation
Top ranking in 2018
Positive
redispatch energy
Classified as
systemically relevant
1. Staudinger Unit 5 517 GWh Not, shutdown in 2025 [46]
2. Karlsruhe (RDK Unit 8) 448 GWh Not, but Unit 4S [47],[48]
3. Heilbronn (Unit 7) 413 GWh Unit 5, 6 (2018,2020)[49],[50]
4. Vorarlberger Illwerke
(Austria) (Hydro power)
365 GWh -
5. Karlsruhe (RDK Unit 7) 347 GWh No, but Unit 4S [47],[48]
.. .. .. ..
7 Staudinger Unit 4 173 GWh 2018 [51]
.. .. .. ..
9 Mannheim (GKM) 157 GWh Unit 7 (2020)[52]
elec tricity transport is superimposed on the requirement
to transmit nationally generated electricity from wind
farms in northern Germany to the load centers in southern
Germany [43].
To avoid an overload of the transmission grid, two main
measures are adopted by the TSOs: redispatch and feed-in
management measures. Both belong to the ancillary
services as well and have received increasing importance
in recent years.
Redispatch means the local reduction or increase in the
feed-in capacity of power plants due to bottlenecks in
the transmission network in order to relieve and stabilize
the grid. Negative redispatch is applied to reduce feed-in
capacity of conventional power plants in northern
Germany in cases of excess power generation of must-run
renewables in geographic proximity. In strong wind
phases, however, even wind farms are assigned by the
TSOs to reduce power input and become part of the
negative redispatch measure. With the employment of
ever-greater numbers of wind farms, renewable energies
are often obligated to throttle their power feed-in as well.
As regulated in the Renewable Energy Sources Act [22],
the operator of curtailed renewable generating units is
entitled to compensation for the lost power feed-in with
guaranteed remuneration.
Positive redispatch is performed on the other side of
the transmission grid – the power sink – by running-up
capacities in the case of excessive transmission rates to
southern neighbors or in the case of the unforeseen trip of
a power plant 16 .
| Figure 9
Redispatch measures in 2018. Negative redispatch via reduction of power
generation (blue), positive redispatch via raise of power generation (both
cumulated) (own illustration with data from [44]).
Energy provided or lost via redispatch is counted in
GWh. Figure 9 illustrates the cumulative generated
redispatch energy in 2018 and the most affected generating
units. The top ranking of power plants clearly shows
that the “award-winning” units for negative redispatch
(Table 1) are located in northern Germany, and the
“award-winning” units for positive redispatch (Table 2) in
southern Germany. For example, the hard coal-fired power
plant Wilhelmshaven (operated by Engie) was not allowed
to feed-in 866 GWh (data taken from [44]) of energy in
2018 due to redispatch measures. In relation to power
capacity, the unit has lost 1185 h (nearly 50 days) of power
generation (full load hour equivalent in Table 1). Considering
its hours of operation and sensitivity to the costs
distribution in Figure 8, it seems to be only a matter of
time before the unit is shut down for operational reasons.
The affected power plant receives renumeration for energy
not generated and for its participation in the redispatch
service regulated in [45].
Table 2 for positive redispatch is headed by the south
German hard coal-fired power plant Staudinger Unit 5,
which usually can be found more on the right-hand side of
the ascending merit order diagram. It was requested for
517 GWh of additional energy. However, in the course of
the German act on the phase-out from the coal-fired power
generation, the utility has already announced it will close
Unit 5 in 2025 [46] because of suffering from low capacity
in the regular market.
The top ten contains also Staudinger Unit 4, a gas-fired
plant, which has already been taken from market and
contracted by the German Bundesnetzagentur 17 (BNA) as
a network reserve power plant. Other affected sites in the
top 5 list contain units which were designated by the utility
to close, but are obligated to remain in operation by the
BNA, which classified the majority of units south of NPP
16 A pumped hydroelectric energy storage in a currently restoring operation modus can also be assigned to stop electricity consumption to not wring out
the power sink furthermore.
17 German Federal Network Agency for Electricity, Gas, Telecommunications, Post and Railway.
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| Figure 10
Totalized capacity of domestic and international grid reserve power plants and identified requirements for the winters/years (in MW) (adapted from [55]).
Grafenrheinfeld 18 as systemically relevant for grid stability.
For further information, references are made in Table 2.
Recently, power plants Moorburg (ranked as #8 in
Table 1) and Mannheim (ranked as #9 in Table 2) were
highlighted in the national media and entered public
discourse [N1], [N2], [N3], [N4]. Power plant Moorburg
is in Hamburg and belongs to the youngest and therefore
most efficient hard coal-fired units. Unfortunately, it was
constructed on the “wrong side” of Germany. Although it
was foreseen in [41] to run until the end of 2038 – the
legally stipulated last year of coal-fired power plants –
Moorburg came to the decision [N1] to apply for the first
tender of the BNA in 2020 to quit coal-fired power generation
against financial compensation. Just recently, both
units of Moorburg had been awarded the contract to quit
electricity generation from hard coal as early as 2021
[53],[54]. Conversely, power plant Mannheim is in the
south and Unit 7 has applied to the operator to be closed. It
will not be allowed to do, however, since it has recently
been classified by the BNA as systemically relevant [52]
until at least 2025. The information was made available to
a broader audience by [N3] and [N4].
If hedged and market-based power plant capacities are
not available in sufficient quantities to carry out redispatch
measures, the TSO will procure the required capacities
from existing, inactive power plants to ensure the safety
and reliability of the electricity supply system (e.g.,
Staudinger Unit 4).
Network reserve power plants are not required
because of insufficient generation capacities, but because
of excessive electricity transmission and the resultant
overload of the transmission network. Generally, these
network reserve power plants are only used outside of the
energy market to ensure grid stability, and thus are used
exclusively for redispatch [43].
The BNA regularly releases reports for future reserve
power plant requirements for the upcoming winter, in
additional to those for the next few years (e.g. [43]). The
numbers of recent reports up to winter 2024/25 have been
picked up and graphically illustrated by [55] as can be
seen in Figure 10. Certain discrete dates are introduced
within, including disturbance values for the capacity
planner. Based on these reports, new build projects can
also be invited to tender. In the case of Irsching [N5], the
energy transition reaches absurd extremes. It was even
described as “insane” by [N6]. Following a tender from the
German TSOs for a new network stability reserve, a new
gas-fired power plant has been awarded at the Irsching
site – it will be known as Unit 6 [56]. Curiously, the utility
applied for the shutdown of Unit 4 and the highly efficient
Unit 5 on several occasions, see Figure 10. Even during the
regulatory approval of emissions for Unit 6, the application
for mothballing Units 4 and 5 was incidentally alluded to
[57]. Irsching Unit 4 and 5 are also taken from market and
contracted by the BNA as network reserve power plants.
Eventually, the provision and application of network
reserve power plant capacities as well as the shedding of
loads is assigned to the range of tasks of the TSOs [9]. For
further information, refer to the annual reports of the BNA
[58], [59], [60], [61]. The redispatch of power plants and
network reserve power plants, as well as the feed-in
management measures regarding curtailment of renewables,
not only play roles of increasing importance for grid
stability, but have also claimed an increasing share in the
price of electricity over the last few years, see Figure 11.
This increasing service is paid for by a levy on electrical
consumption by the end user – the Renewable Energies
Act levy.
| Figure 11
Cost allocation of ancillary services in Million Euro with increasing share of grid stabilizing measures
in % (sum of orange colored segments) (data taken from [9], [58], [62]).
SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 23
18 The so called Mainlinie from the river Main originates from historical and political boundary of the two major powers Austria and Prussia in the 19 th century.
Today it is used amongst others by the BNA to divide the affiliation of power generating units to northern or southern part of Germany.
Serial | Major Trends in Energy Policy and Nuclear Power
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SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 24
Due to the merit order effect of renewables, wholesale
electricity prices have fallen below the marginal costs of
even highly efficient (but expensive) CCGT. Although a
cheaper portfolio of generating units covers the market as
originally intended by the Renewable Energy Sources Act,
renewable technologies are often not the cheapest in terms
of total cost (but not of marginal cost). In markets with
high penetration of renewable energy, this leads to a
divergence between the true cost of the system and the
evolution of the price of electricity in wholesale markets.
In the longer term, investors will be hesitant to reinvest
or recapitalize electricity markets without sufficient
guarantees on returns [20]. In Germany, incentives for
investors are provided by a public feed-in tariff subsidy
program with a guaranteed remuneration to boost the
deployment of renewables. These costs are also borne as a
further part of the Renewable Energies Act levy. Despite
low wholesale prices, the cost of the renewables levy
causes the end consumer to pay the most expensive retail
prices across Europe. Due to the skyrocketing expense of
the levy in recent years, the German government decided
to limit the levy for consumers in 2021 and 2022 by subsidizing
its residual costs with state aid from tax revenues
[63]. Without this subsidy, the levy would increase by
approximately 40 % in 2021 [N7].
The deployment of renewables will be borne by
consumers and taxpayers. But to what extent? A 100 %
penetration of renewables cannot be achieved on standalone
basis without any subsidy program, because
investors of renewable generation would be unable to earn
a return on risk. Electricity prices would be at the renewables’
marginal costs, equal to zero, and renewables could
fall victim to their own success, as stated by [20].
Conventional power generating units are still required
to provide security of power supply, but suffer from low
capacity or have applied for shutdown. Investors would be
discouraged from continuing operation of these units or
even entering the market following tenders for new reserve
power plant capacity. Thus, investments in conventional
generation capacities deemed to be necessary in the long
run have been cancelled. In the end, potential investors
might even call for public support to build conventional
generation capacities. But subsidizing renewables and
conventional capacities would contradict the idea of a
liberal market according to [23].
Another phenomenon has appeared in the public arena
in regard to the energy transition: negative electricity
pricing [N8], [N9]. Colloquially known in Germany as
“Ökostromschwemme” (green power glut) or “Ökostromparadox”
(green power paradox), the term implies that
renewables are responsible. In Figure 4 it can be seen that
conventional generating units have a minimum permitted
limit of partial load operation. In those situations where
the limit is greater than the residual demand – this can
be for a few hours – exceptions to the marked rules may be
needed to avoid shutdowns of generating units that may
not be available when demand increases shortly thereafter
[19]. The power oversupply, with its simultaneous
necessary consumption, leads to negative prices in the
wholesale market. The concept of guaranteed feed-in
remuneration for renewable sources seems to be out of
place during this undesired situation of oversupply and
negative electricity pricing. In an amendment of the
Renewable Energy Sources Act, the 6-hours-rule has been
complemented in 2017. It notes the guaranteed feed-in
remuneration for renewables (with certain power class
determined in the law) will be suspended, if the exchange
electricity price in day-ahead trading is negative for six
hours or more. If this happens, the renewable generating
units do not receive any remuneration retroactively from
the first hour with negative electricity prices. Incentives to
continue operation of renewable generating units are not
only removed, but operators, to ease the situation at the
electricity exchange, also throttle feed-in of renewables.
In this manner, the legislator adjusts one of the misalignments
of the energy transition.
Conclusion
Differing from the usual introductory survey, the paper
opens with the question of what will become of grid
stability. For a better understanding of why the question
arises, the scope of the inquiry has been extended by
explaining basic mechanisms regarding a stable electrical
power grid. Differences have been elucidated for an
electricity sector operating within the “undisturbed”
conditions of a competitive market economy. The entrance
and massive deployment of electricity generation from
renewable sources, whose success is primarily based on a
public subsidy program, undermines market economy
principles. Guaranteed feed-in remuneration elevates
renewables to a specific prioritized position, forcing
conventional generating units out of the market.
Further deployment of highly volatile renewable
sources, along with more conventional generating units
being forced out of the market, makes the power grid
increasingly sensitive to weather-related fluctuations.
Unusual weather phenomena like the Dunkelflaute
constitute major challenges facing the power grid’s supply
security and stability. The largely intermittent output of
solar and wind farms is not correlated with variations in
electricity demand. The oversupply of renewables may be
buffered at low-power demand periods, and the stored
capacity may be fed-in again to the grid at high-power
demand periods when fewer renewable sources are
available. However, large scale battery energy storage
systems, already promisingly announced, are still not in
sight, due to their low levels of capacity and maturity, and
because of their exorbitantly high costs for deployment.
As long as economical energy storage systems are not
established, even proponents of the current alignment of
the German energy transition must admit that reliable
conventional power plants will still be needed for a long
time.
However, new boundary conditions in the electricity
market are challenging for the entire fleet in the conventional
generation portfolio. The merit order effect of
renewables allows them to suffer from low capacities, and
incentives for a continuation of operation, or even for
investments in new generating units, are lagging. All this
at a time when new capacity is particularly required for
grid stability.
The importance of nuclear power plants for supply
security in base load operations, as well as their capability
for highly flexible concurrent grid operation with renewables,
has been demonstrated. The NPPs seem to be made
for the energy transition towards carbon free power
generation. However, the Atomic Energy Act provides an
imminent end of nuclear power generation by end of 2022.
The carbon emission intensive coal-fired power plants,
which are ranked between the NPPs and the expensive
gas-fired power plants in the merit order chart, are also
doomed by the end of 2038 at the latest. As envisaged by
legislators, at least, if not by being abandoned much earlier
by utilities due to operational or economic issues.
Serial | Major Trends in Energy Policy and Nuclear Power
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atw Vol. 66 (2021) | Issue 2 ı March
In a nutshell, unresolved questions remain after the
phase-out of the last NPP and the imagined phase-out of
coal-fired power generation. Which units will be
redispatched to release the grid if there are no units left?
Which unit is capable of conducting large load following
operations? What kind of incentives can be made to
continue the operation (or even for the new builds) of
unpopular but still required conventional power plants?
Who will pay for it?
In the perception of the public, the German energy
transition is also quite unpopular, since the savings from
the merit order effect of renewables (in which most
expensive units are forced out of the market, leading to
lower wholesale prices) do not benefit end consumers.
It is overcompensated by the expenditures for ancillary
services of transmission system operators, essentially the
grid-stabilizing measures.
The misalignment of the energy transition raises these
questions, ones demanding adequate and urgent address.
Otherwise, the initial question remains alarmingly open:
Quo vadis, grid stability?
Abbreviations
BESS
BNA
CCGT
CFPP
GKM
GT
KWU
NPP
PWR
RDK
TSO
Battery Energy Storage System
Bundesnetzagentur, German Federal Network Agency for Electricity, Gas,
Telecommunications, Post and Railway
Combined cycle gas turbine power plant
Coal-fired power plant
Power plant Großkraftwerk Mannheim
Gas turbine power plant
Kraftwerk Union AG (company)
Nuclear Power Plant
Pressurized water reactor
Power plant Rheinhafen Dampfkraftwerk Karlsruhe
Transmission system operator
Nomenclature
c
CT
Δ
ϕ
Boron concentration
Coolant temperature
Delta, difference
Neutron flux
Γ C Boron coefficient of reactivity
Γ CR Control rod coefficient of reactivity
Γ K Coolant temperature coefficient of reactivity
Γ P Power coefficient of reactivity
P Power
Q
Heat flow
ρ C Reactivity contribution based on boron concentration
ρ CR Reactivity contribution based on control rod position
ρ K Reactivity contribution based on coolant temperature
ρ P Reactivity contribution due to load change
s Displacement (of control rods)
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SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 25
Serial | Major Trends in Energy Policy and Nuclear Power
Quo Vadis, Grid Stability? Challenges Increase as Generation Portfolio Changes ı Kai Kosowski and Frank Diercks
atw Vol. 66 (2021) | Issue 2 ı March
SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER 26
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Authors
Dr. Kai Kosowski
Systems Engineering and Safety Analyses
PreussenElektra GmbH, Hannover, Germany
kai.kosowski@preussenelektra.de
Dr. Kai Kosowski received his diploma in mechanical
engineering and was awarded a doctorate in
mechanical engineering in the field of thermodynamics
at the Braunschweig University of
Technology, Germany. He is working as a nuclear
safety engineer at PreussenElektra GmbH since 2009.
Kai has a wide range of experience in the field of
safety analyses with focus on pressurized water
reactors under normal and abnormal operation and
accident conditions.
Frank Diercks
Systems Engineering and Safety Analyses
PreussenElektra GmbH, Hannover, Germany
frank.diercks@preussenelektra.de
Frank Diercks studied Nuclear Engineering and earned
the diploma degree at the Dresden University of
Technology, Germany. He is working in the nuclear
industry for 33 years. In his broad spectrum of
activities, he was also shift supervisor in one of
PreussenElektra’s nuclear power plants. His current
position is defined as principal engineer in the
department Systems Engineering and Safety Analyses.
Serial | Major Trends in Energy Policy and Nuclear Power
Quo Vadis, Grid Stability? Challenges Increase as Generation Portfolio Changes ı Kai Kosowski and Frank Diercks
atw Vol. 66 (2021) | Issue 2 ı March
Challenges and Perspectives
for Long-Term Operation in Switzerland
Natalia Amosova
1 Introduction Switzerland enjoys a long history of exploiting nuclear energy for a significant share of its
national electricity needs. Today, four nuclear power units are in operation in Switzerland. They are Beznau-1 and -2
(1969, 1972), Gösgen (1979) and Leibstadt (1984). Their average age is more than 40 years. All the while, nuclear 1 has
been a subject of great public interest. The public has had significant influence on the country’s nuclear story thanks to
the federal nature of the state, which includes direct democracy.
Nuclear power, and decisions related
to phasing out, continuing operation
or building new reactors has been the
subject of public referenda throughout
the last years and decades. Most
notably, a new federal Energy Strategy
2050 was put to a public vote in May,
2017. 2 The Swiss public voted 58.2 %
in favor of the strategy 3
which has
resulted in a fundamentally changed
outlook for the local nuclear power
industry. The notable result of the
Energy Strategy 2050 in the context of
this article was the entering into force
of an amended Nuclear Energy Act
on 1 January, 2018. The Act now
effectively bans the construction of
nuclear power plants in Switzerland,
by banning the issuance of new
licenses, while allowing the existing
fleet to continue operating. 4
It does
not, however, require any early shutdown
or forced phase-out of power
plants.
A year prior to the Energy Strategy
2050, in November 2016, an initiative
to phase out nuclear power in
Switzerland more rapidly by limiting
reactor lifetime to 45 years was unsuccessful,
garnering only 45.8 % of
the vote. 5
Looking back, there had
been progress towards a sustainable
future with nuclear at its core. In early
2011, prior to the earthquake and
tsunami leading to the Fukushima
disaster, the canton of Bern voted in
favor of a second nuclear power plant
at the site of the existing Mühleberg
NPP. Starting in 2008, a company
was formed by two of the country’s
existing nuclear utilities tasked with
working towards the licensing for two
new Generation III reactors, one each
at the site of existing reactors Beznau
and Mühleberg. The Fukushima
disaster and resultant changes in public
perception and business strategy
led to an end of these activities.
Today’s legal and regulatory regime
governing the licensing of Swiss
nuclear power plants does not limit
operation as long as safety obligations
are fulfilled. 6
The result being that
Switzerland is set to continue to enjoy
many TWh of nuclear power each year
for the coming decades. The Swiss
Nuclear Energy Ordinance from
December 10 th , 2004 was modified in
April, 2017 to address enhanced safety
reviews for reactors operating beyond
four decades. 7
The regulatory body
specifies the detailed requirements on
proof of safety for long-term operation
(LTO). 8 The licensee addresses these
LTO-specific requirements as a part
of the periodic safety review (PSR)
process. The relevant Swiss regulatory
guidance, ENSI-A03 on PSR for
nuclear power plants, was amended in
2018 to include the concept of LTO
and associated safety case requirements
to be regularly included in the
PSR from 40 years of licensee operation
and beyond. The required elements
of a safety case for LTO are the
ageing management programs, the
safety analysis of major reactor components
(e.g. the reactor pressure vessel,
large elements of the nuclear steam
supply system and the reactor containment
structure), updating analyses
(deterministic and probabilistic) and
backfitting. Leibstadt is the only
licensee yet to submit its 40-year PSR. 9
| Figure 1
Operational Nuclear Power Plants in Switzerland. © Nuklearforum 2021
Swiss nuclear power plants have
consistently been heavily backfitted,
thanks in part to the Swiss regulatory
requirement that state-of-the-art
technology is utilized. 10
Today, all
Swiss NPPs have filtered containment
venting systems (installed prior to
Fukushima), bunkered systems for
shutdown and heat removal, and
seismically robust spent fuel pools
with two physically separated lines to
feed them from outside. 11 Switzerland
is not typically thought of as a seismically
active zone, and yet it is one of
the primary natural hazards for
structures in the country. In many
ways nuclear power plants are
amongst the most earthquake-proof
structures in Switzer land. 12 After the
Fukushima disaster, the regulator
(ENSI) required the licensees to prepare
a series of updated sa fety cases,
culminating with a detailed deterministic
‘extended’ seismic safety case
which was submitted this year. The
seismic hazard assumptions dic tated
27
ENERGY POLICY, ECONOMY AND LAW
1 Power, waste, research and medical isotopes.
2 Volksinitiative «Für den geordneten Ausstieg aus der Atomenergie»
3 https://www.bfs.admin.ch/bfs/de/home/statistiken/politik/abstimmungen/jahr-2017/2017-05-21.html
4 The legal changes include, in addition, the ban on nuclear fuel reprocessing (now without a deadline) and the ban on fundamental changes to nuclear facilities.
5 https://www.bk.admin.ch/ch/d/pore/va/20161127/det608.html
6 OECD/NEA, Legal Frameworks for Long-Term Operation of Nuclear Power Reactors
7 Nuclear Energy Ordinance (NEO) of 10 December 2004 (Status as of 1 February 2019) (SR 732.11)
8 ENSI-A03 Periodic Safety Review for Nuclear Power Plants
9 Switzerland’s Eight National Report to the Convention on Nuclear Safety, 2019
10 In practice, this means that backfitting is a continuous process.
11 Switzerland’s Eight National Report to the Convention on Nuclear Safety, 2019
12 https://www.ensi.ch/en/wp-content/uploads/sites/5/2016/05/Neubestimmung_Erdbebengefaehrdung_KKW_PEGASOS_PRP.pdf
Energy Policy, Economy and Law
Challenges and Perspectives for Long-Term Operation in Switzerland ı Natalia Amosova
atw Vol. 66 (2021) | Issue 2 ı March
ENERGY POLICY, ECONOMY AND LAW 28
by the regulatory body are higher
than ever before, and partially exceed
the Great East Japan Earthquake as
experienced by Fukushima Daiichi
reactors are wholly (in the case of
Beznau) or partially owned by three
utilities: Axpo Power AG, Alpiq AG
and BKW Energie AG. The association
Nuclear Power Plant in 2011. 13
of Swiss nuclear power station
In 2013, the state-owned utility
BKW made the decision to permanently
operators, swissnuclear, represents
the common interests of the licensees
shut down its Mühleberg and is the country’s single WANO
Nuclear Power Plant. The reasons
behind this decision were strictly
category 1 member.
Local nuclear regulation is unique
business-related and not political to Switzerland. That is to say that
according to BKW leadership. 14
The Switzerland, a customer country for
plant closed permanently as planned
in December, 2019 and BKW immediately
GE and Westinghouse reactor technology,
did not replicate the regulatory
began decommissioning and infrastructure of America 16
– even
dismantling activities.
though, some years earlier, in the
1840’s, the Swiss constitution was
strongly influenced by the American
model. Owing to the existence of
both American and German reactor
technology, regulatory guidance in
Switzerland foresees two possible
nuclear design codes, ASME Section II
Division 1 and the KTA standards.
Although this fact does allow for some
flexibility when it comes to equipment
sourcing, in Switzerland it is not
permitted to mix design codes within
a single plant system and the design
modification process is costly.
2 Swiss nuclear landscape
Switzerland has a colorful nuclear
history which has included:
p The purchase of the SPHIR reactor
in 1955(-1994) after it was part of
the first International Conference
on the Peaceful Uses of Atomic
Energy in Geneva
p The design, construction and
commissioning of the heavy-water
DORIT research reactor (1960-
1977) by a BCC, Sulzer Brothers
and Escher-Wyss joint venture
aptly named Reactor Ltd.
p The core meltdown of a homegrown,
if short-lived, experimental
nuclear power reactor in Lucens
(1968-1969, INES Level 4)
Switzerland’s contemporary large
reactor fleet is notably heterogeneous.
The three remaining operating power
plants (after Mühleberg’s shutdown)
comprise four reactor units including
one General Electric BWR-6 Mark 3
(Leibstadt), two 2-loop Westinghouse
PWRs (Beznau-1 and -2) and a
Siemens KWU (Gösgen). 15 The overview
is shown in the Table 1. These
Name Type Status Reference
Unit Power
[MWe]
3 Ageing management in
Switzerland
Ageing management is undoubtedly a
strong suit of Swiss NPPs. Switzerland
was one of the first countries to introduce
systematic ageing management
programs when, in 1991, the regulatory
body requested the power plants
to introduce and maintain an ageing
management program (AMP) for
safety-related structures, systems and
components (SSC). 17 This was around
20 years before the International
Generic Ageing Lessons Learned
First Grid
Connection
Model
BEZNAU-1 PWR Operational 365 1969-07-17 W (2-loop)
BEZNAU-2 PWR Operational 365 1971-10-23 W (2-loop)
GOESGEN PWR Operational 1010 1979-02-02 KWU 3 Loop
LEIBSTADT BWR Operational 1220 1984-05-24 BWR-6
MUEHLEBERG BWR Permanent
Shutdown
2019-12-20
373 1971-07-01 BWR-4
| Table 1
Nuclear Power Plants in Switzerland. Data from Nuclearplanet © Nuklearforum 2021.
(IGALL) first appeared. They integrate
the findings of research programs
including those at the Paul Scherrer
Institute, the Electric Power Research
Institute, VGB Power Tech and the
OECD. In 2011, the Swiss regulatory
body introduced a guideline specific
to ageing management, ENSI-B01.
The scope of the AMP programs covers
civil, mechanical and electrical
aspects. In 2017, the Swiss regulator
decided that the licensees would
participate in the first European topical
peer review effort, which ENSREG
decided would be focused on ageing
management. The result of the TPR in
Switzerland pointed towards an overall
satisfaction with ageing management
experience in the country.
4 Public perception
Public perception plays such a large
role in the business of nuclear power
in Switzerland due to a political
system which allows for popular initiatives
(Volksinitiative) to amend the
constitution of the country. The Swiss
nuclear power industry was lucky to
survive the first initiative of an antinuclear
flavor when in 1979 a complete
and immediate ban on nuclear
electricity generation was scraped by
with a majority of 51.2 % less than
40 days before the Three Mile Island
accident. 18
Nuclear energy also survived
the next three initiatives before
a decade-long ban on new nuclear
power plant construction, stemming
from the Chernobyl disaster, passed in
1990. While similarities can be drawn,
there are fundamental differences in
Switzerland and Europe’s nuclear
power prospects in the 1990’s versus
the 2020’s. Correspondingly, there are
differences in the way today’s ban on
new nuclear licenses is perceived in
Switzerland versus that of the 1990’s.
In much of the world, nuclear
power is attacked by opponents for
failure to find a disposal solution for
radioactive waste. The case in
Switzerland is no different. By law,
radioactive waste is to be disposed of
in deep geological repositories located
within Switzerland according to a
polluter pays principle. Currently, the
government foresees the general
licensing procedure being completed
around the start of the next decade,
and operation in the 2050-2060
13 https://www.ensi.ch/en/2016/05/31/updated-seismic-hazard-assumptions-require-new-safety-cases-to-be-drawn-up-for-swiss-nuclear-power-plants/
14 https://www.nzz.ch/schweiz/muehleberg-akw-abschalten-1.18176306
15 In this regard, Switzerland’s nuclear fleet is in many ways similar to that of Spain.
16 Unlike Spain, South Korea or Slovenia who, for example, follow the same model for quality assurance at nuclear power plants found in U.S. 10CFR50 Appendix B.
17 https://inis.iaea.org/collection/NCLCollectionStore/_Public/45/054/45054717.pdf?r=1
18 GWEBER, R.. Geschichte der Kerntechnik in der Schweiz - Die ersten 30 Jahre 1939-1969, 978-39-07-17516-3, NaturaMed Jungjohann, 1992
Energy Policy, Economy and Law
Challenges and Perspectives for Long-Term Operation in Switzerland ı Natalia Amosova
atw Vol. 66 (2021) | Issue 2 ı March
timeframe. While the site and repository
itself may not yet be operational,
the financing for these operations (as
well as decommissioning) are secured
through a polluter pays system. An
independently reviewed cost study is
prepared every 5 years to ensure
that both the disposal and decommissioning
funds under federal oversight
are on track. 19
Switzerland is not lacking in safe
and successfully operating interim
storage facilities and waste management
programs. An interim waste
storage facility called ZWILAG has
been in operation since 2000 with a
new storage hall for low- and mediumlevel
waste fully operational since
mid-2020. ZWILAG has successfully
employed a plasma plant for the treatment
of radioactive waste for more
than a decade. At Gösgen NPP, a
unique wet, passively-cooled interim
storage facility for spent fuel has been
in operation since 2008. Locally, Swiss
nuclear power plants maintain strong
support for ongoing operation thanks
to the significant socioeconomic benefits
brought on by such infrastructure.
5 Economics
The permanent shut down of Mühleberg
NPP demonstrated that Swiss
utilities are willing to cut reactor lifetimes
short if the economics of future
operation is uncertain or no longer
feasible. The history of nuclear power
globally has shown many operational
factors directly impact profitability.
These include the ability to satisfy
changing regulatory demands, to
secure the necessary spare parts and
equipment for upgrades, and to maintain
a capable and competent workforce.
Other factors, such as variations
in the cost at which generated electricity
can be sold, also play a role.
Like many European and North
American nuclear operators, Swiss
nuclear utilities are challenged by
developments within the extended
enterprise. These are changes within
the supply chain leading to the obsolescence
of safety-related SSCs.
Thankfully, inventory levels at Swiss
NPPs have not been squeezed as
means of cost saving over the last
decades quite like many international
counterparts. Although just-in-time
procurement is not unheard of, the
plants often enjoy enough critical
spares for many years of operation,
sometimes even enough to last until
end-of-life. Nonetheless, obsolescence
issues are a rising concern for Switzerland
and Europe alike. 20 Another issue
which arises with an evolving supply
chain and a fast-paced industrial
world is undeclared digital content
(or undeclared design changes in
general). In 2017, due to a series of
incidents, the regulator initiated
inspections related to supply chain
management which included warehousing,
parts sourcing and quality
documentation review.
Switzerland is set to fully liberalize
its electricity market under a new
Electricity Supply Act.
6 Supply chain
commitment
The businesses of nuclear suppliers
based in Switzerland, Austria and
Germany have historically hinged on
the large German nuclear fleet. Due to
the nuclear phase-out underway in
Germany, a number of suppliers are
phasing out their nuclear product
lines, especially those designed
specifi cally according to KTA rules. 21
The phaseout of nuclear power in
Germany is already having an impact
on Swiss NPPs’ ability to find the
right parts at reasonable prices and
acceptable quality from original
equipment manufacturers, forcing
the utilities to consider alternative
markets like France or the United
States for parts and services.
The new German energy mix,
comprised of a coal and gas base load
and volatile photovoltaic parks and
wind farms, has also challenged the
economic viability of Swiss NPPs
directly by strongly affecting the price
of electricity on the market.
7 Leadership, expertise
Maintaining a talented and diverse
workforce is crucial for the LTO of the
Swiss fleet. Thanks to the existence of
a joint nuclear engineering master’s
program between the ETH Zurich and
EPF Lausanne, some locally educated
manpower has entered the industry. 22
The Swiss labor market has enjoyed
decades of low unemployment.
Some licensees noted the challenges
associated with maintaining the
necessary expertise in order to fulfill
the latest regulator guidance on the
subject, noting that it is “somewhat
difficult to recruit suitable personnel
and then to motivate them in the long
term.” 23
Undoubtedly there are challenges
associated with work which requires
intensive training but comes with an
expiry date. The Swiss nuclear operators
benefit from the German nuclear
phase-out as experienced manpower
is being freed up and is sometimes
willing to cross the border, if only
during the day.
8 Conclusions
The majority of Switzerland’s nuclear
fleet is safely and successfully running
in long-term operation, demonstrating
the resilience and promise of nuclear
power technology. Crucial to this success
has been capable and experienced
plant staff, a supply chain which can
be counted on for high-quality items
and service, as well as a mature regulatory
infrastructure which demands
the state-of-the-art for the benefit of
public and environmental safety.
The subject of phase-out versus
continued operation continues to be a
subject of discussion in Switzerland.
Just as a Volksinitiative could one day
overturn the existing ban on nuclear
new-build, so could it bring an early
end to this chapter of Switzerland’s
nuclear power story. For the time
being, the Swiss nuclear fleet is well
positioned to continue operating
safely for decades to come.
Author
Natalia Amosova
Principal Consultant
Apollo Plus GmbH, Zurich, Switzerland
namosova@apolloplus.com
Ms. Natalia Amosova is a mechanical engineer and a lean six sigma black belt
with more than a decade of experience in the nuclear industry. Thanks to her roles
as sales engineer, project manager and executive she brings significant expertise
in the global supply chain, international nuclear projects, regulatory compliance
strategies and business development at all stake holder levels. In her work as
Principal Consultant at the Zurich-based nuclear industry consultancy Apollo+,
Ms. Natalia Amosova is supporting key projects within the-new build and LTO
sectors as well as inter national initiatives.
ENERGY POLICY, ECONOMY AND LAW 29
19 A plant life of 50 years is assumed.
20 MARTIN Oliver, ABBT Matheus. Current Challenges of the European Nuclear Supply Chain, 978-92-76-20872-3 (online), Publications Office of the European Union, 2020
21 Only three Siemens KWU type reactors will be operating in Europe after 2022 – Borssele in the Netherlands, Trillo 1 in Spain and Gösgen in Switzerland.
22 New Master of science in nuclear engineering, Interview with Professor H.M. Prasser. ATW-International Journal for Nuclear Power 53(2), 2008
23 Kernkraftwerk Gösgen, Contribution to the National Assessment Report, Topical Peer Review 2017, Document-No. BER-S-92652 accessed 30, December 2020
https://www.ensi.ch/en/wp-content/uploads/sites/5/2018/01/KKG-Topical-Peer-Review-2017_web-2.pdf
Energy Policy, Economy and Law
Challenges and Perspectives for Long-Term Operation in Switzerland ı Natalia Amosova
atw Vol. 66 (2021) | Issue 2 ı March
ENERGY POLICY, ECONOMY AND LAW 30
From Fossil Fuel Super Power to
Net Zero – Can Australia Deliver
an Orderly Energy Transition?
Dayne Eckermann, Oscar Archer and Ben Heard
Introduction Australia is arguably one of the best-endowed nations on Earth in energy resources, being a major
exporter of coal, gas and uranium, with large solar and wind resources. Yet establishing an effective energy policy
environment, one capable of coordinating a transition to a decarbonised future, has proven inordinately challenging.
Australia is a collective of seven separate jurisdictions working to meet their own policy agendas, while attempting to
coordinate through governmental bodies to meet national energy challenges. The Australian energy landscape is now
undergoing major changes in both power generation and energy extraction and export, as the reality of acting on
climate change is increasingly visible in global energy policies and technology trends. As Australia lurches awkwardly
into a cleaner energy future, it must grapple with the shift from a major fossil fuel exporter to clean energy developer,
while ensuring those trading partner communities and economies are transitioned justly to a clean energy future.
Pressing questions for Australian policy makers are, how can they effectively and efficiently transition Australia away
from its existing energy system into the new clean future? And do they have all the tools necessary to do so?
| Figure 1
Australian energy trade, 2018–19.
(Source: Department of Industry, Science, Energy and Resources (2020) ‘Australian Energy Statistics’)
Discussion
Energy policy in Australia can be
broadly grouped into two distinct
aspects: energy production and
export, and electricity consumption.
The former remains a mainstay of
state economies and the Australian
economy at large. The latter is becoming
a greater challenge, as a
nation approaching 30 million people
grapples with the need to decarbonise
while its electricity market has undergone
major structural changes over
the past two decades that have not
necessarily been in the best interests
of decarbonisation.
Old King Coal, LNG and
Yellowcake
Australia exports two-thirds of all the
energy it produces 1 , the majority in
the form of coal and liquefied natural
gas (LNG). Australia has the third
largest reserves of coal in the world
(149 Gt 2 ) and is the largest exporter
of coal globally. Coal is a major source
of trade income, accounting for
A$64 billon in 2019. Thermal coal accounts
for A$22.7 billion, with the
majority shipped to Japan and China.
These exports are a major part of the
economies of Queensland and New
South Wales, with a recent unofficial
ban on Australian coal imports by
China causing considerable concern 3 .
Beyond retaliatory trade actions, the
global trend away from coal appears
to be well-underway. In 2019 the
globe recorded its first reduction
in absolute coal consumption in
modern times, led by steep declines in
developed nations. As the major
beneficiary of coal exports, the time
for Australia to adapt appears to be
nigh, or already well-upon it.
In recent years Australian energy
export growth has been dominated
by the rise of LNG exports to Asia.
Australia is now the second largest
exporter of LNG globally behind
Qatar, exporting 104.7bcm in 2019 4 ,
with the majority heading to Japan
and China. In the past decade, LNG
exports have grown by 17 % per year 5
and 72 % of all domestic gas produced
is exported as LNG 6 . Gas continues
to provide an attractive option for
quickly deployed growth in energy
consumption that, while being a fossil
fuel, provides both greenhouse gas
and air pollution advantages over
coal, as well as quick-start flexibility
to respond to fluctuating variable
renewable energy. Continuing economic
growth in Asia, coinciding
with imperatives for cleaner air and
emissions reduction, has only increased
the need for gas. While a
challenging and complex market,
1 Department of Industry, Science, Energy and Resources, ‘Australian Energy Update 2020’, p. 33 https://www.energy.gov.au/publications/australian-energy-update-2020
2 BP, ‘Statistical Review of World Energy 2020’, p. 44
3 https://www.abc.net.au/news/2020-12-16/will-other-countries-replace-china-buying-australian-coal/12985956
4 ‘Statistical Review of World Energy 2020’, p. 42
5 ‘Australian Energy Update 2020’, p. 33
6 ibid, p. 9
Energy Policy, Economy and Law
From Fossil Fuel Super Power to Net Zero – Can Australia Deliver an Orderly Energy Transition? ı Dayne Eckermann, Oscar Archer and Ben Heard
atw Vol. 66 (2021) | Issue 2 ı March
Australia as a whole has been a major
export beneficiary.
Australia has been a producer of
uranium since the early 1900s and
exporter since the 1950s 7 . Australia
has the largest known reserves of
uranium globally – 28 % – and is the
world’s third largest producer 8 . The
majority of this known resource is
located in the state of South Australia,
which hosts the major poly-metallic
Olympic Dam mine. Australia
exported 7,195 t of uranium in 2019
and, owing to its bilateral export
agreements with consumers, every
tonne is used for peaceful purposes 9 .
If Australia’s uranium was accounted
for in terms of primary energy in a
light water reactor (LWR) it would be
similar to the current energy exports
of LNG. The electricity produced from
this uranium in standard LWRs is
equivalent to 243 TWh annually 10 –
approximately equal to Australia’s
annual electricity consumption 11 .
While the financial value of uranium
exports is minor compared with coal
and gas, the energy value is comparable,
and easily expanded in line with
changes in demand.
Most recently, Australian governments,
as well as private investors,
have considered pathways to export
Australia’s renewable energy endowment,
either converted into an
energy carrier such as hydrogen or
ammonia, or delivered directly to
export markets via high-voltage direct
current (HVDC) transmission many
times longer and more challenging
than the largest connector in the globe
today. Such ventures remain early,
speculative and investigatory, and
might yield pro ductive export
opportunities in future. However the
gap to substitution of A$103 billion in
coal and gas exports is a gigantic one,
and depends on potential markets
failing to develop domestic options at
lower cost.
The National Electricity Market
The National Electricity Market
(NEM) is an interconnected power
network across the States of
| Figure 2
The Olympic Dam mine is a large poly-metallic underground mine located in South Australia.
It is the fourth largest copper deposit and the largest known single deposit of uranium in the world.
(Source: BHP)
Queensland, New South Wales (including
the Australian Capital Territory),
Victoria, South Australia and Tasmania.
Together this forms one of the
largest electricity networks in the
world by distance, but with a relatively
lean 9 million customers. Each of
these states’ networks form regions in
the NEM, which collectively came into
being as a wholesale energy market in
December 1998 12 .
Development of the power systems
in the post-war years was conducted
by State authorities to serve the
growing demand for electricity. The
Snowy Hydro Scheme was the largest
and most ambitious project during
these years, delivering an interconnection
of the NSW and Victorian
grids in 1959 13 .
The NEM was the result of a Special
Premiers conference in 1991 to
establish a National Grid Management
Council “to encourage and coordinate
the most efficient, economic and environmentally
sound development of
the electricity industry in eastern and
south-eastern Australia having regard
for key national and State policy objectives”
14 . In 1993 the Hilmer Report
detailed measures to improve national
competition and recommended the
structural separation of public
utilities, including electricity generation,
transmission and system and
market operation. It was noted that
the existing system was inefficient and
exhibited no competition 15 . The following
year the Council of Australian
Government (COAG) developed a
code of conduct for the operation of
the National Grid, and in 1996 the
participating jurisdictions agreed to
pass the National Electricity Law.
South Australia was connected to
Victoria in 1989 prior to the above
reforms, but has since added a second
DC link and uprated the original AC
interconnection in 2015. Queensland
was connected to New South Wales in
2001 and in 2005 Tasmania was
connected to the mainland via the
Basslink undersea HVDC, creating the
NEM as we know it today.
These new legislative and regulatory
instruments were to be maintained
by the National Electricity
Code Administrator (NECA), and the
operation of the National Grid was to
be undertaken by the National
Electricity Market Management
Company (NEMMCO). Both these
bodies still exist today and are
known by their subsequent titles, the
Australian Energy Regulator (AER)
and the Australian Energy Market
ENERGY POLICY, ECONOMY AND LAW 31
7 World Nuclear Association, ‘Australia’, https://www.world-nuclear.org/information-library/country-profiles/countries-a-f/australia.aspx
8 ibid
9 Australian Safeguards and Non-proliferation Office, Annual Report 2019,
https://www.dfat.gov.au/publications/international-relations/asno-annual-report-2019-20/report/html/section-2-4.html
10 ibid
11 The National Electricity Market (NEM) incorporates the States of Queensland, New South Wales, Victoria, South Australia, Tasmania and the Australian Capital
Territory, and is one of the largest interconnected electricity networks in the world.
12 AEMO, ‘About the National Electricity Market’,
https://aemo.com.au/en/energy-systems/electricity/national-electricity-market-nem/about-the-national-electricity-market-nem
13 CIGRE, ‘Electricity in Australia’, 1996, https://www.ewh.ieee.org/r10/nsw/subpages/history/electricity_in_australia.pdf
14 National Grid Management Council, 1992, National Grid Protocol
15 H. Outhred, ‘The Evolving Australian National Electricity Market: An Assessment’, 2004,
http://www.ceem.unsw.edu.au/sites/default/files/uploads/publications/200404AssessingNEM0404.pdf
Energy Policy, Economy and Law
From Fossil Fuel Super Power to Net Zero – Can Australia Deliver an Orderly Energy Transition? ı Dayne Eckermann, Oscar Archer and Ben Heard
atw Vol. 66 (2021) | Issue 2 ı March
ENERGY POLICY, ECONOMY AND LAW 32
Operator (AEMO) respectively. A
third body was established in 2005,
the Australian Energy Market Commission
(AMEC), and assumes the
role of rulemaking and market
development for the operation of the
electricity wholesale market and
transmission regulation. In simple
terms, AEMC sets the rules, AER
enforces these rules, and AEMO
operates the market within these
rules. Any participant in the NEM
can propose new or amended rules
via AEMC to improve the functions of
the NEM.
At great distance from the NEM,
Western Australian and the Northern
Territory have their separate networks
and are operated under different
markets. There have been proposals
to link Western Australia to South
Australia via 2,000 km HVDC interconnection,
but none have progressed
past the concept stage. The Western
Australian market is different to the
NEM in that it has both a wholesale
trading component and capacity component.
In 2006 the South Western
Interconnected System in Western
Australia (SWIS) was established and
has similar authorities to the NEM
who rule-make, regulate and operate.
Australia also has a spread of micro
networks for remote settlements
and industrial operations, such as
mining – but nearly 80 % of power
consumption is through the NEM,
with the majority of the remainder
through the SWIS and the grid of the
Northern Territory.
The early years of the NEM history
were focused on the deregulation of
the existing state-owned and operated
electricity assets, and the interconnection
of the separate regions to
form a national grid. The National
Electricity Market is structurally comprised
of generators owned by private
entities, regulated monopolies providing
transmission and distribution,
and retailers. In some cases generation
asset owners are also retailers –
‘gentailers’ – who operate in both the
wholesale generation and over-thecounter
markets for electricity. In the
state of Queensland these generation
assets are owned by state companies
who operate and retail these electricity
assets. While they are private
entities under law, the state has
retained ownership of these assets
(known as Government-owned corporations).
In simple terms, the NEM worked,
in terms of effective operation of a
mature generation and transmission
system requiring limited new investment.
Wholesale power prices were
affordable and stable, and system
security was high.
Climate Accords and
Renewable Energy Targets
However, just as this relatively new
national grid was undergoing its
establishment and operation under
new rules and structures, a transition
began, away from a fossil fuel heavy
energy mix to one primarily focused
on renewable energy.
In 2001 the Commonwealth
government instituted the Mandatory
Renewable Energy Target (RET) that
aimed to source two percent of the
nation’s electricity from renewable
energy. The RET works by the creation
of tradeable certificates for every
megawatt hour of electricity produced
from renewable sources. These are
traded to liable entities that must
meet their renewable energy quotas.
Wholesale purchasers of these certificates
surrender these to the Clean
Energy Regulator each year as defined
by the regulations 16 .
With a very modest target of two
percent, any impact of the RET on the
early years of the NEM were relatively
minor. However, the 2007 Federal
election, in particular, was a critical
year for energy policy in Australia.
Both the Government and Opposition
promised to implement national emissions
reduction policies if elected,
with the Government of the day indicating
that development of a nuclear
sector would support Australia’s
transition away from fossil fuels. The
newly elected Labor government of
Prime Minister Kevin Rudd expanded
the RET in 2009 to twenty percent or
41,000 GWh by 2020. With a change
in government in 2013, this was
downscaled to 33,000 GWh in 2015,
after a review into the target indicated
that the Australian economy was
consuming less power than had been
forecast.
In addition to the Renewable
Energy Target, the Clean Energy
Finance Corporation and Australian
Renewable Energy Agency were
established in 2012 to aid in the
finance and commercialisation of
clean and renewable energy projects.
CEFC is a corporate Commonwealth
entity and has access to A$10 billion
in funding. It has a remit to invest
directly and indirectly into renewable
and low carbon technologies and has
enabled A$27.3 billion in additional
private sector investments Australia
wide 17 . ARENA has the function to
“improve the competitiveness of
renew able energy technologies and
increase the supply of renewable
energy through innovation”. Since
inception ARENA has supported
566 projects with A$1.63 billion in
funding, leading to $6.69 billion in
renewable energy investment 18 .
ARENA also provides a pathway for
projects at the innovation stage to
reach commercialisation.
Together, these schemes have been
instrumental in the growth of renewable
energy over the past two decades.
Today, renewable electricity comprises
over 20 % of electricity generated
in Australia 19 , with swift growth
in supply from onshore wind, and
latterly solar PV.
However, the election of the Rudd
Government also precipitated an
especially dysfunctional period of
Commonwealth politics, often referred
to as “the Climate Wars”, which
arguably continues today. While detailed
discussion is outside the scope
of this article, climate change and energy
policies played a central role in
Australia being led by six Prime Ministers
in eleven years from 2007–2018.
This dysfunction and lack of durable
policy is perhaps a barometer of how
fundamentally Australia’s domestic
and export economy is tied to fossil fuels.
The Renewable Energy Target was
the only durable climate- and-energy
policy at the Commonwealth level. 20
The simple and popular focus on
boosting the contribution of power
from lowest-cost renewable energy
generation was effective. It also
precipitated serious challenges to the
security of the network which persist
today.
System Black
In September 2016 South Australia
arrived at a perfect storm of weak
network system strength, failure of
transmission lines and the unknown
16 Clean Energy Regulator, ‘How the scheme works’, http://www.cleanenergyregulator.gov.au/RET/About-the-Renewable-Energy-Target/How-the-scheme-works
17 Clean Energy Finance Corporation, ‘CEFC 2019-2020 investment update’, 2020, https://www.cefc.com.au/media/1w3l53yd/cefc_investmentupdate_2019-20.pdf
18 Australian Renewable Energy Agency, https://arena.gov.au/about/
19 OpenNEM, ‘Energy: NEM’, https://opennem.org.au/energy/nem/?range=all&interval=1y
20 https://www.sbs.com.au/news/the-recent-history-of-australia-s-climate-change-wars
Energy Policy, Economy and Law
From Fossil Fuel Super Power to Net Zero – Can Australia Deliver an Orderly Energy Transition? ı Dayne Eckermann, Oscar Archer and Ben Heard
atw Vol. 66 (2021) | Issue 2 ı March
| Figure 3
One of several collapsed electricity pylons near Melrose in South Australia's Mid North
(Source: ABC News, Tom Fedorowytsch)
unknowns of wind farm power electronics
settings. Prior to this event,
AEMO and the South Australian transmission
network operator, ElectraNet,
studied the impact of the increasing
shares of renewable energy – namely
wind – and noted that, in low inertia
conditions & a failure of the main
SA-Vic AC interconnector, the network
would not cope in the face of
unplanned events, raising the risk of
substantial or total network failure 21 .
This is exactly what happened on
the 28 th September 2016. A freak
storm brought down three 275 kV
transmission lines in South Australia,
causing voltage disturbances on
the network. These disturbances
triggered fault ride-though protection
systems in 445 MW of wind capacity,
tripping them offline. In order to
arrest the drop in frequency, 900 MW
of power was suddenly needed
through 600 MW of interconnection
to Victoria. The SA-Victoria interconnector
exceeded its safety limits,
and ultimately tripped. These series of
cascading events resulted in the entire
state of South Australia going offline –
a system black 22 .
This event shocked the Australian
energy community, such that in an
extraordinary meeting on 7 th October
2016, the Coalition of Australian
Governments (COAG) 23 energy ministers
agreed to an independent review
of the NEM to assess system security
to ensure any policies or developments
into the future do not result in
another State-wide blackout. This led
to the “Finkel Review”.
The Finkel Review – a new
path to coordination?
The Independent Review into the
Future Security of the National
Electricity Market was Chaired by
Australia’s Chief Scientist Dr Alan
Finkel. The review highlighted a lack
of secure Commonwealth energy and
climate policy was “pushing up prices
and undermining reliability”. It popularised
the concept of an “energy
trilemma” in Australia denoting the
competing challenges of affordability,
low carbon, and reliability and security.
The review outlined a blueprint
with a vision for the future of the
NEM, focusing on: increased security;
future reliability; rewarding consumers;
and lower emissions. The review
called for a plan based on three
pillars of strengthened governance,
systems planning and an “orderly
transition”, warning that in the
absence of these conditions “the
system will stumble again in future”.
The post-Finkel era in Australian
energy policy has led to notable
governance and planning changes.
Firstly, the formation of the Energy
Security Board, whose role is to
coordinate the implementation of the
reform blueprint from the Finkel
Review and report on system security
and reliability risks and threats in the
NEM. It is comprised of an independent
chair and co-chair, and the
CEOs of AEMO, AEMC and AER. It sits
within the COAG energy council and
reports to the responsible Commonwealth
and State energy ministers 24 .
Secondly, AEMO has the responsibility
to assist in in the “orderly
tran sition” by publishing recurring
Integrated System Plans and Renewable
Integration Studies.
The Integrated System Plan (ISP)
and Renewable Integration Studies
(RIS) provide illustrative future
roadmaps for the efficient transition
to a low carbon future. The ISP is a
biannual modelling and reporting
process that provides signposts towards
a least-cost system, particularly
as a means to plan efficient investment
in transmission infrastructure. It
presents several scenarios, identifies
renewable energy zones where
development of generation is likely to
be favourable, and provides a roadmap
of the required network augmentations
beginning with the most
certain, “actionable” investments 25 .
The RIS is a study that assesses the
challenges and potential risks of
integrating large amounts of solar and
wind into the NEM in the coming
decade 26 .
Superficially, the ISP infers that
nearly all black coal will be displaced,
in an orderly way, by the additional of
wind, solar and storage by the early
2040s. However, this belies the codependency
of new power projects
with a vast expansion of the transmission
network of the NEM. New
power projects depend on new transmission
to be able to develop, and new
transmission projects rely on assumed
power developments to make the case
that they will deliver value to consumers.
Currently the network is
constrained; the most promising
regions of renewable energy supply
are under-served by transmission, and
the ability to move power between
major demand centres is limited. At
the time of writing, a major new interconnector
from Robertstown in South
ENERGY POLICY, ECONOMY AND LAW 33
21 AEMO & ElectraNet, ‘Update to renewable energy integration in South Australia’, 2016
22 AEMO, ‘Black System South Australia 28 September 2016’, 2017, https://www.aemo.com.au/-/media/Files/Electricity/NEM/Market_Notices_and_Events/
Power_System_Incident_Reports/2017/Integrated-Final-Report-SA-Black-System-28-September-2016.pdf
23 It is important here to note the role COAG plays in the formation of energy policy in Australia. While the Commonwealth and State governments are free to make and
enact their own energy policies, the COAG energy committee provides a forum where energy ministers can discuss and in some cases coordinate policies. It was this
group, along with AEMO, AER and AEMC, that has now become the de-facto coordinating body for energy policy in the NEM.
24 COAG Energy Council, Energy Security Board, http://www.coagenergycouncil.gov.au/market-bodies/energy-security-board
25 AEMO, Integrated System Plan, https://aemo.com.au/energy-systems/major-publications/integrated-system-plan-isp
26 AEMO, Renewable Integration Study, https://aemo.com.au/energy-systems/major-publications/renewable-integration-study-ris
Energy Policy, Economy and Law
From Fossil Fuel Super Power to Net Zero – Can Australia Deliver an Orderly Energy Transition? ı Dayne Eckermann, Oscar Archer and Ben Heard
atw Vol. 66 (2021) | Issue 2 ı March
State Goal Support mechanisms
ENERGY POLICY, ECONOMY AND LAW 34
QLD 50 % RE by 2030 Green Bonds from Queensland Treasury Corporation (low cost finance);
Advance Queensland initiative (government grants) 29
NSW
35 % emissions reduction below 2005 levels
by 2030
Australia to Wagga Wagga in NSW
is in limbo 27 . Tendered capital costs
have substantially exceeded estimates,
and one of the transmission
partners is unwilling to proceed unless
it can recoup revenue from consumers
early – before the project is complete.
Meanwhile the 2020 Health of the
NEM report published by the Energy
Security Board identified that system
security continues to be rated “moderate
to critical”, the most concerning
issue in the NEM 28 . 293031323334
So, while these new initiatives
illustrate a renewed focus on system
planning, it is arguable that the pillars
of governance, planning and orderly
transition are not yet being optimally
fulfilled. Each state has enacted their
own targets to meet State-wide energy
policy objectives such as targets for
renewable electricity and emissions
(see Table 1). While the Commonwealth
government is committed to
an emissions reduction target of
26-28 % below 2005 levels, by 2030,
each state and territory has committed
in prin ciple to a net-zero by
2050 target 35 . While this arguably
makes Australia a de-facto “net-zero
by 2050” adopter, there remains a
material difference between the value
and impact of these State-based
targets and aspirations, and the
potential value of clear and enduring
climate and energy policy from the
Commonwealth.
12 GW of solar and wind through tenders for Long Term Energy Service
Agreements 30
Vic 50 % RE by 2030 Reverse auctions to award hybrid payment mechanism
(a mix of fixed price payment and contract-for-difference) 31
Tas 200 % RE by 2040 (largely hydro) No committed support mechanisms yet 32
SA
50 % emissions reduction below 2005 levels;
Net 100 % RE by 2030 33
No committed support mechanisms yet
ACT 100 % RE ACT Government reverse auctions for contracted RE supply,
monthly FiTs 34
| Table 1
Committed State goals. RE = Renewable Energy
Divergent, aspirational energy
policies from the States occurs as a
response to perceived inadequacies of
Commonwealth-level policy leadership.
Whether such policy leadership
eventually takes the form renewed
targets, durable carbon pricing, or
other investment frameworks, investor
certainty is required to replace
approximately 16 GW of firm coalfired
generation that is expected to
exit the market by 2040.
In summary, since the system black
event of 2016, there is increased coordination
and planning, with a focus on
reducing emissions, en hancing affordability,
and main taining reliability and
security. This is assisting a somewhat
more orderly transition to be undertaken.
However there remains an
absence of over arching policy, as well
as a catch-up job required to expand the
transmission network and address the
challenges of system security from high
penetration variable renewable energy.
The efforts in Australia to date
exclusively consider the challenge
through the lens of integrating large
amounts of variable renewable generation.
These efforts have excluded
preparation to deploy a proven low carbon
technology with which Australia
has had only a flirting relationship.
The nuclear question
Australia has Commonwealth and
State prohibitions on the construction
of nuclear power. Relevant Commonwealth
legislations specifically
dis allow any Ministerial approval of a
nuclear power plant. Three States
have outright nuclear power prohibitions
and the others prohibit the
storage and transportation of nuclear
waste (see table 2). However, in the
past two years there have been three
government inquiries that have
looked at their respective prohibitions.
In the cases of New South
Wales 36 and the Commonwealth 37 ,
both recommended that their respective
prohibitions be lifted and further
investigation is under taken into the
feasibility of nuclear in Australia.
This isn’t the first time Australia
has looked into the feasibility of
nuclear power. In the 1950s the
Australian Atomic Energy Commission’s
(AAEC) was involved in nuclear
power research in close partnership
with the United Kingdom. During the
1950s and 1960s the AAEC recognised
with government ministers each State
was considering the use of nuclear
power for their growing industrial
economies and managing different
reactor designs at the Commonwealth
level would add complexity to any
legislative regime 38 .
At this time electricity and energy
production in each State was planned
and developed by government boards,
trusts and commissions. At this time
South Australia was looking at a small
27 https://www.adelaidenow.com.au/news/south-australia/sansw-interconnector-on-shaky-ground-with-finance-plan-set-to-be-rejected/news-story/
f750f41a014366354d3c1991d2705eb5
28 COAG Energy Council, ‘Health of the NEM 2020’, 2021, http://www.coagenergycouncil.gov.au/publications/2020-health-nem
29 https://www.qld.gov.au/environment/climate/climate-change/transition/queensland-climate-transition-strategy https://www.qtc.com.au/institutional-investors/green-bonds/
https://advance.qld.gov.au/grants
30 https://energy.nsw.gov.au/government-and-regulation/electricity-infrastructure-roadmap
31 https://www.energy.vic.gov.au/renewable-energy/victorias-renewable-energy-targets https://www.energy.vic.gov.au/__data/assets/word_doc/0016/80512/
VRET-fact-sheet-Auction.docx
32 http://www.dpac.tas.gov.au/divisions/climatechange/tasmanias_climate_change_action_plan_20172021/advancing_our_renewable_energy_capability
33 https://www.environment.sa.gov.au/topics/climate-change/south-australias-greenhouse-gas-emissions
34 https://www.environment.act.gov.au/energy/cleaner-energy/how-do-the-acts-renewable-energy-reverse-auctions-work
35 https://www.climatecouncil.org.au/resources/what-does-net-zero-emissions-mean/
36 https://www.parliament.nsw.gov.au/committees/inquiries/Pages/inquiry-details.aspx?pk=2525#tab-reportsandgovernmentresponses
37 https://www.aph.gov.au/nuclearpower
38 K. Adler, Australia’s Uranium Opportunities, 1996, p. 37
Energy Policy, Economy and Law
From Fossil Fuel Super Power to Net Zero – Can Australia Deliver an Orderly Energy Transition? ı Dayne Eckermann, Oscar Archer and Ben Heard
atw Vol. 66 (2021) | Issue 2 ı March
Jurisdiction
Nuclear prohibitions
Commonwealth
advanced gas cooled reactor, and
Mt Isa in Queensland was looking
at a reactor for its heavy industry 39 .
A national consultative committee
on nuclear energy was established in
1969 and concluded the Commonwealth
should develop a reactor
project to standardise the design, set
the standards for regulations and
approvals, and thereby enhance the
economic benefits of serial production.
It was decided a 500 MWe
plant be constructed on Commonwealth
land at Jervis Bay in NSW. A
com petitive tender was put out
globally and received two PWR
designs from Westinghouse and Kraftwerkunion,
a CANDU design from
Canada, and the Steam Generating
Heavy Water Reactor (SGHWR)
design from the UK 40 . The SGWHR
design was chosen, but due to a
change in Common wealth government
leadership the project was
delayed and ultimately cancelled.
As mentioned, the State energy
boards were conducting their own
parallel investigations into nuclear
Environment Protection and Biodiversity Conservation Act 1999 (s140A)
Australian Radiation Protection and Nuclear Safety Act 1998
New South Wales Uranium Mining and Nuclear Facilities (Prohibitions) Act 1986
Victoria Nuclear Activities (Prohibitions) Act 1983
Queensland Nuclear Facilities Prohibition Act 2007
South Australia Nuclear Waste Storage Facility (Prohibition) Act 2000
Western Australia Nuclear Waste Storage and Transportation (Prohibition) Act 1989
Tasmania
n/a
Northern Territory Nuclear Waste Transportation, Storage and Disposal (Prohibition) Act 2004
| Table 2
List of nuclear facilities and waste prohibitions in Australia.
power. For example, the Electricity
Trust of South Australia had engineers
at Hartwell nuclear facility in the UK
in the 1950s 41 , the State Electricity
Commission of Victoria undertook a
major feasibility study in the 1970s
and 1980s to develop nuclear power
plants to support heavy industry, with
a desire to build a Sizewell B SNUPPS
reactor at four potential sites 42 .
Thus, Australia has on numerous
occasions come surprisingly close to
developing a nuclear power sector,
and even a uranium enrichment
facility in South Australia in the 1980s.
In 2006 the Commonwealth government
initiated a review into nuclear
power alongside a government committee
inquiry into the nuclear fuel
cycle, and both recommended that
Australia remove its prohibitions and
undertake feasibility studies into
nuclear. These developments in the
1980s and 2006 were followed shortly
by the prohibitions listed in Table 2.
This was tested in 2014 with the
highest level of inquiry in Australia
through a Royal Commission into the
Nuclear Fuel Cycle in South Australia.
It too, after hearing from experts from
all sides of the debate, recommended
these pro hibitions be lifted, and South
Australia seriously consider becoming
an international repository for the
management of high level waste from
civilian power reactors.
The new kid on the block
Owing to stagnant demand, the integration
of intermittent generation,
and arguably a loss of appetite for very
large projects, traditional large nuclear
reactors might not be an optimal solution
for Australia. Smaller generation
increments is likely a better fit for
purpose. This is where Small Modular
Reactors can play a pivotal role.
Small Modular Reactors are generally
regarded as units of 300 MWe
or less. This makes a tech nically
ideal substitute for a portion of the
incumbent fossil fuel generation
sector. Presently the largest single
generating unit in the NEM is a
750 MWe coal plant (Kogan Creek).
SMRs would hence connect to the
ENERGY POLICY, ECONOMY AND LAW 35
39 ibid, p. 39
40 K. Adler, p.41
41 ibid, p. 39
42 https://www.crikey.com.au/2011/03/21/for-victoria-nuclear-power-was-oh-so-close/
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Energy Policy, Economy and Law
From Fossil Fuel Super Power to Net Zero – Can Australia Deliver an Orderly Energy Transition? ı Dayne Eckermann, Oscar Archer and Ben Heard
atw Vol. 66 (2021) | Issue 2 ı March
ENERGY POLICY, ECONOMY AND LAW 36
existing transmission network, with
no upgrades required and, as a reliable
supplier, would utilise that network
efficiently. SMRs would also provide
much of the essential inertia in the
grid that is required to maintain
system security with greater penetrations
of asynchronous renewable
generation. Presently, SMRs are not a
com mercially available proposition,
for Australia or any other Western
nation. However, progress in the SMR
sector in 2020 was notable, and it is
now plausible to speak of first power
from several leading SMR developers
before 2030, and accelerating thereafter.
This timeframe is highly relevant
to a successful “orderly transition” of
the Australian power sector, with
departure of coal fired generation
forecast to accelerate from 2030 –
2040. However, SMRs cannot simply
be acquired on a commercial basis
once proven beyond doubt elsewhere.
Australia will need to take judicious
steps to build upon its existing
regulatory environment (already
familiar with non-power reactor build
and operation), and prepare the
institutional supports to enable the
whole-of-life commitment that is the
hallmark of a modern nuclear power
industry. Such a planned approach is
comfortably analogous to the reality
that has revealed itself from the
uptake of renewable energy – progress
cannot and will not be achieved
without intention, planning and coordination,
which must be sufficient to
unlock the necessary investment.
This work ought to begin immediately.
While Australia’s extraordinary
relative dependence on fossils fuels is,
perhaps, an understandable legacy,
there is no question of the burden it
places on Australia in enacting a swift
transition to net-zero. To continue to
exclude nuclear technologies is to
overlay that legacy burden with an
extraordinary, and wholly voluntary
handicap.
Summary
Our overview of energy policy in
Australia has explored two key
themes: our expansive energy exports
that are fuelling Asian economies, but
are heavily comprised of fossil fuels;
and the transition of the domestic
electri city market towards low carbon
ources. While the establishment of
the National Electri city Market delivered
a successful early experience
with operations driven by market economics,
the escalating shocks of
integrating renewable energy into the
network in more recent years have
also prompted a more planned and
deliberate approach. We are now
seeing better planning and reporting
of the key challenges of energy policy,
notably around the ‘energy trilemma’,
and the nature and magnitude of
measures taken to ensure effective
and orderly transition. Many communities
reliant on old energy (coal
mining and old power station towns,
in particular) deserve a just transition
to ensure their health and wellbeing. It
is promising to see that governments
are paying more attention to these
issues and planning ahead. However it
is not going to be an easy transition –
Australia is only at the beginning
of this journey, the chal lenges are
already present, and a continued
absence of durable climate and energy
policy from the Commonwealth is
compounding these challenges.
We additionally argue that excluding
nuclear energy – one of the
single largest sources of low carbon
energy worldwide – is a monumental
and unnecessary handicap to
Aus tralia’s efforts to deliver effective
energy policy in general, and leadership
in climate action in particular. A
move away from over a decade of
energy dysfunction and towards
enduring investment and action is
likely to require both the setting of
energy investment policies and
guidelines that are transparently
tied to a net-zero by 2050 goal, as
well as the genuine technology
neutrality of the removal of prohibitions
of nuclear technologies, with a
roadmap to deployment of modern
SMRs. The pressure of global trends
in policy and technology will mount
every year these conditions remain
unmet.
For readers wanting a more detailed
account of energy policy in Australia,
Matthew Warren’s book 'Blackout:
How is energy-rich Australia running
out of electricity?’ is a great read on
the recent events that have marked
Australia’s energy policy over the past
decade. Looking at how Australia
arrived at the events that marked 2016,
and what can be done for the future,
from the perspective of someone who
has been involved in Australia’s energy
industry.
Author
Dayne Eckermann
General Manager
NGO Bright New World
dayne@
brightnewworld.org
Dayne Eckermann is the General Manager of
Australian environmental NGO Bright New World.
The core ethos of Bright New World is ‘Stable Climate,
Rich Nature, Prosperous Humanity’, and is the first
environmental NGO in Australia to openly advocate
for nuclear energy as part of a portfolio of clean
energy sources. Dayne has several years’ experience
working in the mineral resources and energy sectors
in South Australia.
Co-Authors
Dr. Oscar Archer
Senior Advisor
Bright New World
Oscar Archer is a doctoral organic chemist who has
been studying the energy/climate issue for 15 years,
and helps out at Bright New World as senior advisor.
His focus is nuclear industrial heat, as well as
the opportunities and challenges presented by
nuclear waste management. He has appeared
on ABC Radio National's Ockham's Razor and writes
at The Actinide Age.
Dr. Ben Heard
Founder
Bright New World
Ben Heard is a doctoral qualified energy analyst,
and founder and Chairperson of environmental NGO
Bright New World. He has been providing commentary
and analysis on Australian energy issues for over
ten years, and is a globally recognised voice in
support of the use of nuclear technologies as part
of a clean energy mix.
Energy Policy, Economy and Law
From Fossil Fuel Super Power to Net Zero – Can Australia Deliver an Orderly Energy Transition? ı Dayne Eckermann, Oscar Archer and Ben Heard
atw Vol. 66 (2021) | Issue 2 ı March
Extending Nuclear Plant Licenses
to 80 Years – Essential to Achieve
a Reliable Future Energy Mix
James Conca
If America doesn’t extend the licenses of most of our nuclear power plants for an additional 20 years, bringing their
lifetimes up to 80 years, we will have no hope of significantly curbing fossil fuel use in America. Similarly for Japan,
Germany and elsewhere in the world.
While renewables are increasing rapidly
in the United States, hydro and
nuclear are still the most prolific
energy sources that offset significant
amounts of fossil fuels, and will be for
at least 20 more years. Nuclear alone
produces more power 1
than hydro,
wind, solar, geothermal and storage
combined, at an average production
cost of only 4 ¢/kWh 2 .
Most assessments of power supply
adequacy in various regions, like that
of the Pacific Northwest Power Supply
Adequacy Assessment for 2021 3 ,
realize that imminent closures of coal
baseload plants to achieve emissions
goals are threatening the grid reliability
in the 2020s, especially since
they may be replaced by intermittent
renewables.
Installation of new renewables
requires significant installation of new
natural gas plants, not to mention
significant installation of thousands of
miles of transmission lines and new
infrastructure since these are almost
always a significant distance from the
main users.
States and countries that have
closed nuclear plants have seen
carbon emissions go up 4 .
All assessments also understand
that keeping existing nuclear plants
operational is essential to maintaining
the grid into our new energy future.
There are dire predictions about
reliability for the late 2020s.
Both hydro and nuclear plants
have long-term lives and most units
are expected to exceed 80 years. Large
hydro like Grand Coulee and Hoover
are expected to substantially exceed
100 years. Having these units last so
long is a critical component of getting
to a clean energy future and a major
element in the cost savings needed to
achieve that future.
Maintaining existing nuclear plants
cuts the cost of producing electricity in
half relative to installing new units 5 of
either hydro or nuclear. According to
the EIA, maintaining existing nuclear,
at 4¢/kWh, is the same as installing
new natural gas plants and onshore
wind 6 , both at 4¢/kWh, even with the
presently low gas prices.
Our nuclear plants were originally
licensed for 40 years. Contrary to
public opinion and anti-nuke concerns,
this number had nothing to do
with design life, or safety issues, or
component degradation, or anything
technical. 40 years was an arbitrary
time period chosen in the 1950s by
the Atomic Energy Commission – the
predecessor to the present Nuclear
Regulatory Commission (NRC) and
the Department of Energy (DOE) – as
just a reminder to take an all- encompassing
relook at the plant and make
sure all systems are working well
enough to handle another 20 years –
that the integrity of the concrete
and steel is good, that cables, piping
and penetrations are good, and
that all other components are up to
speed.
If a nuclear power plant gets a
license extension, as almost all do in
America, the NRC requires another
look every 20 years after that. Most
of our operating nuclear power plants
have already had their licenses
renewed 7 for the first time, so are now
licensed to operate for 60 years 8 .
Many nuclear plants are already
| Closing most of America’s perfectly- good working nuclear plants for no good
reason before their expected 80-year working life is finished, like Diablo
Canyon Nuclear Power Plant located near Avila Beach, California shown
here, robs us of cheap carbon- free power, loses an enormous amount of
money, and will require the installation of over 150 GW of natural gas, or
300 GW of wind, to replace.
planning for the next cycle to extend
their life to 80 years.
Duke Energy, which operates
eleven nuclear reactors at six sites in
North and South Carolina, is seeking
second 20-year renewals 9
of the
operating licenses for all of its nuclear
reactors, starting with the three-unit
Oconee plant for which it expects to
submit a renewal application in 2021.
The company has set itself carbon
reduction goals of at least 50 % by
2030 and net-zero by 2050, and states
that the units are key to the company
achieving its carbon emissions goals.
Together, Duke’s reactors have a
combined generating capacity of over
10,700 MWe, which would require
about 30,000 MWe of wind, and
almost as much new natural gas, to
replace.
ENERGY POLICY, ECONOMY AND LAW 37
1 https://www.eia.gov/tools/faqs/faq.php?id=427&t=3
2 https://www.world-nuclear.org/information-library/economic-aspects/economics-of-nuclear-power.aspx
3 https://www.nwcouncil.org/media/7150591/2016-10.pdf
4 https://www.forbes.com/sites/jamesconca/2019/01/16/u-s-co2-emissions-rise-as-nuclear-power-plants-close/#5779e7b47034
5 https://www.nei.org/news/2018/cost-of-nuclear-generation-reaches-10-year-low
6 https://www.eia.gov/forecasts/aeo/pdf/electricity_generation.pdf
7 https://www.energy.gov/sites/prod/files/2020/04/f73/NEGTN02-%23227578-v8-NUCLEAR_INDUSTRY_SCORECARD_SUMMARY.pdf
8 http://www.nrc.gov/reactors/operating/licensing/renewal/applications.html
9 https://news.duke-energy.com/releases/duke-energy-will-seek-to-renew-nuclear-plant-licenses-to-support-its-carbon-reduction-goals
Energy Policy, Economy and Law
Extending Nuclear Plant Licenses to 80 Years – Essential to Achieve a Reliable Future Energy Mix ı James Conca
atw Vol. 66 (2021) | Issue 2 ı March
Nuclear Plant Unit Capacity Operational Life Unit Capacity Operational Life
ENERGY POLICY, ECONOMY AND LAW 38
Crystal River 3 860 MW 1977-2013 (closed 2009)
San Onofre 2 1,070 MW 1983-2012 3 1,080 MW 1984-2012
Kewaunee 1 556 MW 1973-2013
Vermont Yankee 1 620 MW 1972-2014
Fort Calhoun 1 482 MW 1973-2016
Clinton 1 1,069 MW 1987-2017
Quad Cities 1 934 MW 1973-2018 2 937 MW 1973-2018
Pilgrim 1 680 MW 1973-2019
Indian Point 2 1,020 MW 1974-2020 3 1,040 MW 1976-2021
| Table 1
Recent Premature Closings.
Nuclear Plant Unit Capacity Operational Life Unit Capacity Operational Life
Diablo Canyon 1 1138 MW 1985-2024 2 1118 MW 1986-2025
Fitzpatrick 1 813 MW 1975-?
Ginna 1 580 MW 1970-?
Nine Mile Point 1 613 MW 1969-? 2 1,277 MW 1988-?
Three Mile Island 1 819 MW 1974-2019
Oyster Creek 1 619 MW 1969-2019
Salem 1 1,169 MW 1977-? 2 1,158 MW 1981-?
Hope Creek 1 1,172 MW 1986-?
Peach Bottom 2 1,308 MW 1974-? 3 1,309 MW 1974-?
Pallisades 1 805 MW 1971-2022
Davis-Besse 1 894 MW 1978-2020
Duane Arnold 1 601 MW 1975-2020
Perry 1 1,256 MW 1987-2021
Beaver Valley 1 921 MW 1976-2021 2 905 MW 1987-2021
Byron 1 1164 MW 1985-2021 2 1136 MW 1987-2021
Dresden 2 902 MW 1970-2021 3 895 MW 1971-2021
LaSalle 1 1137 MW 1984-? 2 1140 MW 1984-?
Braidwood 1 1194 MW 1988-? 2 1160 MW 1988-?
| Table 2
Planned or Potential Premature Closings by 2026.
Whether a plant is operating in
its 40 to 60-year period, or its 60 to
80-year period, nuclear plants are
required to conduct aging-management
programs to monitor the status
of components, systems and structures,
and ensure they continue to
meet standards of safety and reliability.
The nuclear industry spends
significant capital 10
maintaining and
upgrading these plants to last for
these lengths of time, over $20 billion
over a two-year period alone.
These annual expenditures will
decrease somewhat in the years to
come as all of the post-9/11 enhancements
have been completed, most of
the Fukushima-related upgrades have
been implemented, the first license
extensions are mostly done and fuel
costs are dropping even further.
Capacity factors are at a record high of
92 %, producing more energy for the
same cost. The industry expects that
overall costs will fall even more, about
30 % within the next few years.
In light of this stellar record, the
recent spate of premature closings of
smoothly-working nuclear plants is
mind-boggling. Kewaunee, Vermont
Yankee, Pilgrim and Oyster Creek,
Indian Point – over 4,000 MW of
capacity employing 7,000 people and
producing over 30 billion kWhs a
year – had all been renewed for another
20 years before they were closed. Even
more plants are schedule to close soon,
losing almost 40,000 MW of carbonfree
generation (Tables 1 and 2).
10 https://www.nrc.gov/docs/ML1708/ML17088A885.pdf
Energy Policy, Economy and Law
Extending Nuclear Plant Licenses to 80 Years – Essential to Achieve a Reliable Future Energy Mix ı James Conca
atw Vol. 66 (2021) | Issue 2 ı March
Advertisement
The premature closing of the
Pilgrim plant, for example, will cost
Massachusetts $500 million and
devastate the local community. In
fact, replacing Pilgrim’s 100 billion
kWhs of carbon-free electricity that it
would have produced over the next
20 years at about 5¢/kWh ($5 billion
total) would cost over $12 billion for
wind, biomass or geothermal, and
over $25 billion for solar.
Massachusetts is hoping to just buy
hydro from Canada, but the state is
almost certain to replace this energy
with natural gas at about $10 billion,
and just take the carbon hit.
The reasons for these closings are
warped wholesale electricity markets
and the politics of irrational fear.
Federal and state mandates and
tax credits for renewable generation
suppress prices, particularly during
off-peak hours. Some regions see
negative prices each day because most
of the operating costs for renewables
are paid for by taxpayers, instead of
ratepayers. So renewables can often
charge nothing, thereby appearing to
be cheaper than nuclear.
Because nuclear runs 24/7 and is
the most reliable source of electricity,
some nuclear plants have to pay a
bizarre fee called a congestion charge
of up to $10/MWh just to get on the
grid. Renewables don’t have to pay
that charge because they are not
reliable and do not produce electricity
most of the time. Something is really
wrong when nuclear, constantly producing
at 4¢/kWh, is considered too
expensive, as it is in the western PJM
market.
Yes, warped is the correct term.
Renewing the licenses for nuclear
plants makes sense for consumers
because it preserves an affordable and
dependable source of electricity. As
Richard Myers, Vice President of the
Nuclear Energy Institute, put it at
the annual Platts Nuclear Energy
Conference 11 in D.C., “By maintaining
our existing nuclear plants, license
renewal preserves the fuel and
technology diversity that is the bedrock
of a reliable, resilient system.
Continuing to operate our nuclear
plants will sustain the carbon reductions
that will be achieved through
any Clean Power Plan or successors.”
Then there’s the looming problem
of our aging infrastructure. In 2030,
92 % of our power plants will be over
25 years old, half of them will be
over 50 years old. While nuclear and
hydro plants can run for 80 years or
more, almost nothing else can. We
are going to have to replace about
80 % of our generating capacity by
2040 unless we really don’t care if
the lights turn on when we hit the
switch.
Extending nuclear licenses to
80 years will ease the enormous
challenge we face in replacing
and modernizing our electricitygenerating
infrastructure over the
next few decades. It will save over
$300 billion in new construction and
save about 400 million tons of carbon
from entering the atmosphere from
America alone.
And this assumes we will install
another 200,000 MW of wind and
solar during this time, itself quite
challenging but doable with sufficient
political will, 400,000,000 tons of
steel, a billion tons of concrete, and
a whole lot of copper, silver, neodymium,
indium, tellurium and
high-purity silica.
But the nuclear and renewable
industries are ready for it. We don’t
want another Dark Age.
Author
Dr. James Conca
Senior Scientist
UFA Ventures, Inc.
Richland, USA
jim@ufaventures.com
Geochemist and Energy scientist, speaker and author
Dr. James Conca is Senior Scientist for UFA Ventures,
Inc. in the Tri-Cities, Washington, a Trustee of the
Herbert M. Parker Foundation, an Adjunct Professor at
Washington State University in the School of the
Environment, an Affiliate Scientist at Los Alamos
National Laboratory and a Science Contributor to
Forbes on energy and nuclear issues. Conca obtained
a Ph.D. in Geochemistry from the California Institute
of Technology in 1985, an MS in Planetary Science in
1981, and a Bachelors in Geology and Biochemistry
from Brown University in 1979.
Join Conca’s ZOOM talks
for all aspects of nuclear, energy,
climate change and planetary
science for audiences of
all types, public and scientific.
The most popular subjects include:
ı The GeoPolitics of Energy –
Achieving a Just and Sustainable
Energy Distribution by 2040
ı
A Green New Deal that Can Work
ı Climate Mitigation –
Do We Have a Plan B?
ı Humans and the Environment –
The Ethics of Energy
ı Iran and North Korea –
Different Faces of the Bomb
ı
Dirty Bombs – The Terror and the Truth
ı Our Aging Infrastructure –
A Precarious Future
ı
ı
ı
ı
Radiation and the Value
of a Human Life
The Actual Costs of Energy
Why Are We so Afraid of Nuclear?
What Nuclear Has Shown Us
about Our Solar System?
Check out
What’s Happened to
Our Nuclear Waste Program?
Interested?
Please email to jim@ufaventures.com
ENERGY POLICY, ECONOMY AND LAW 39
11 http://www.platts.com/commodity/electric-power
Energy Policy, Economy and Law
Extending Nuclear Plant Licenses to Conca 80 Years Anzeige – Essential 75x260v1.indd to Achieve a Reliable 1 Future Energy Mix ı James Conca
14.02.21 12:12
atw Vol. 66 (2021) | Issue 2 ı March
SITE SPOTLIGHT
EDITORIAL 40
Beznau Nuclear Power Plant –
Decades of Safe, Environmentally
Friendly Power Generation
The Beznau nuclear power plant was the first commercial nuclear power plant in
Switzerland, and it can look back on more than five decades of safe, reliable, and
environmentally friendly electricity generation. Despite being operational for more
than 50 years – Unit 1 went into operation on December 9, 1969 – Beznau is one of
the safest nuclear power plants in the world. Its operator, Axpo, has undertaken
upgrades and modernization investments worth more than CHF 2.5 billion since
the plant was commissioned, thus ensuring that it is always state of the art and
complies with the regulatory standards. The nuclear power plant is a model for the
rest of the world. In line with Swiss law, Axpo plans to operate the power plant as
long as it is safe and economical to do so.
Facts & Figures
The Beznau nuclear power plant (KKB) with its two
units (Beznau Unit 1 and Beznau Unit 2) is located on
Beznau Island (Switzerland) in the Lower Aare Valley
and is operated by Axpo Power AG. The twin-unit
plant is supple mented by the on-site interim storage
facility for the storage of radioactive waste and spent
fuel ( ZWIBEZ). The ZWIBEZ will continue to exist as an
independent nuclear facility even after both units
have been completely decommissioned, and will continue
to be operated on the basis of the existing unlimited
operating license.
The Beznau nuclear power plant consists of two 2-loop
Westinghouse pressurized water reactors of almost
identical design, each with a thermal reactor power of
1,130 MW and a net electrical output of 365 MW. The
total annual production of the plant is around
6,000 giga watt hours, which is roughly twice the
amount of electricity consumed by the city of Zurich.
Since the plant was commissioned, more than
270 tera watt hours of environmentally friendly power
have been generated in total, saving far in excess of
300 million tonnes of CO 2 , the amount which would
have been produced if this power had been generated
by a coal-fired power plant.
The Beznau Nuclear Power Plant generates valuable
baseload energy around the clock with the exception
of a few weeks in the year when fuel rods are replaced
or upgrades are carried out. The two units satisfy
around 10% of Switzerland’s annual electricity
requirements and thus make a significant contribution
to Switzerland’s electricity supply.
Around 450 staff and 100 third-party employees work
permanently at the power plant. These are engineers,
chemists, technicians, radiation protection officers,
electricians, administration staff and specialists, maintenance
workers and cleaners, planners and security
controllers, occupational security and QC staff, finance
specialists, and specialists for the treatment of nuclear
waste.
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A team of security officers works in three shifts to
safeguard the plant. Six shift groups (plant and reactor
operators, shift managers) ensure that the plant is
operating safely.
When the annual upgrades are being carried out, up
to 1,000 people are working on the site. This has a positive
impact on the regional economy.
Apart from producing power, the plant has been
supplying hot water to the regional district heating
network (REFUNA) in the Lower Aare Valley since 1983.
The thermal energy is supplied via heat exchangers,
which are supplied with steam from the high-pressure
and at the low-pressure section of the steam turbines.
The thermal power provided for the district heating
supply reduces the electric power output of the
nuclear power plant by up to 7.5 MW.
Technical Data
Beznau Unit 1 and 2 | 2-loop PWR
p Net power: 2 x 365 MWel
p Production: > 270 TWh from start of operation
p Utilization factor: > 81 % Beznau Unit 1
> 88 % Beznau Unit 2
p No. of employees: 450 permanent staff
p Fuel elements in core: 121
p Fuel elements per year: Approx. 20 per reactor
→ 320 kg U/fuel element
p Number of operating periods: 46 (Unit 1)
47 (Unit 2)
Source: IAEA
Commissioning
On May 12, 1969, the Eidgenössisches Verkehrsund
Energiewirtschaftsdepartement, now the Eidgenössisches
Departement für Umwelt, Verkehr,
Energie und Kommunikation (Federal Department of
Environment, Transport, Energy, and Communi cations)
granted Axpo the start-up authorization for Unit 1.
Commercial operation began on December 9, 1969.
Unit 2 was commercially commissioned on March 4,
1972. Units 1 and 2 each have an unlimited operating
license.
Beznau nuclear power plant
Operator: Axpo Power AG
Milestones Unit 1 Unit 2
Start of construction Sep. 1, 1965 Jan. 1, 1968
First criticality Jun. 30, 1969 Oct. 16, 1971
First grid connection Jul. 17, 1969 Oct. 23, 1971
Commercial operation Dec. 9, 1969 Mar. 4, 1972
Cost of new build
Investments
750 million Swiss francs
2.5 billion Swiss francs
Mode of operation
Both units of Beznau nuclear power plant were
planned and built by the Westinghouse and Brown,
Boveri & Cie. (BBC) consortium. The thermal power of
one reactor unit is 1,130 MWth and the gross electric
power is 380 MWel. The water in the primary loop
flows through the reactor core at high pressure
(154 bar) and the heat generated in the reactor is
transferred to the secondary loop in the steam
generators. The pressure in the secondary loop is
lower, so live steam is generated there. This is fed to
the two turbines in the turbine building via the live
steam lines. In each steam turbine, the live steam is fed
through the high-pressure turbine to the low-pressure
turbines. The generator converts the rotational energy
of the steam turbines into electrical energy.
On leaving the turbine, the steam condenses to water
in the condenser. This water, also known as condensate,
is reheated in the secondary loop and pumped
back into the steam generators by the condensate and
feedwater pumps. The condenser is cooled with river
water (from the River Aare) which flows through the
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EDITORIAL 42
1– Control rod drive
2 – Reactor pressure
vessel
3 – Pressurizer
4 – Control rods
5 – Fuel elements
6 – Main reactor pump
7 – Steam generator
8 – High-pressure
economizer
9 – Feedwater tank
10 – Feedwater pump
11 – Low-pressure
economizer
12 – Condensate pump
13 – Condenser
14 – High-pressure
turbine
15 – Low-pressure
turbines
16 – Generator
17 – Transformer
18 – Water separator,
reheater
19 – Refuna steam
extraction
20 – Refuna heat
exchanger
Figure 1: Overview primary and secondary loop with cooling.
plant by virtue of the natural gra dient between the
headwater channel and the natural course of the Aare
(approx. 6 meters) (Figure 1). The secondary loop is
principally free from radio activity, which means the
maintenance of the steam turbines is much easier than
that of a boiling water reactor, for example. Each unit
at Beznau nuclear power plant uses two steam turbinegenerator
sets built by BBC. The gross electric power of
each unit amounts to 190 MWel. The steam to generate
the district heating for the REFUNA is also taken
from the steam turbines.
The plant
The illustration below (figure 2) shows a cross-section
through the containment building of Unit 1, the
auxiliary building with the spent fuel pool, the intermediate
building with the main control room, and the
turbine building.
The two cylindrical containment buildings of Unit 1
and 2 are the landmark feature of Beznau nuclear
power plant. These twin-walled buildings are approx.
67 meters high with a diameter of around 38 meters,
and they house the reactor cooling system (primary
loop) with the reactor pressure vessel, the main reactor
pumps, the pressurizer, and the steam generators. The
primary loop is enclosed by a gas-proof steel pressure
shell (3), which in turn is completely surrounded
by a concrete envelope (1) at a distance of 1.5 meters.
The space between the steel pressure shell and the
concrete envelope is called the cavity. It has a gasproof
steel lining (2) on the inside of the concrete wall.
The fuel store for new and spent fuel elements is
adjacent to the containment building. The four steam
turbine-generator sets and the condensers and further
components are housed in the turbine building.
The containment of the Beznau nuclear power plant
consists of
P the primary containment (steel pressure shell
with filtered pressure relief system, safety vessel,
containment) and
P the secondary containment (cavity with liner,
separate ventilation system, and outer concrete
containment).
The primary containment consists of a gas-proof steel
pressure shell and forms the first safety barrier around
the primary loop. Maintaining a low pressure in the
cavity between primary and secondary containment
counteracts any escape of air-borne radioactivity.
In a beyond-design-basis accident, the formation of
steam/gas can cause such a high pressure to develop
inside the steel pressure shell that its integrity may be
compromised. Beznau has various security systems in
place to cope with such beyond-design-basis accidents.
They include a filtered pressure relief system and the
hydrogen recombinators, for example. In the event of
such a malfunction, the pressure relief system allows
the steam/air mixture to escape from inside the containment
to the outside – after first being cleaned and
filtered to minimize the escape of air- borne contaminants.
On the inside, the steel pressure shell is fitted
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Figure 2: Schematic overview containment building and turbine building.
1 – Concrete envelope
2 – Steel liner
3 – Steel pressure shell
4 – Reactor pressure
vessel
5 – Control rod drive
6 – Steam generator
7 – Main reactor pump
8 – High-pressure
turbine
9 – Water separator/
reheater
10 – Low-pressure
turbine
11 – Generator
12 – Transformer
13 – Condenser
14 – Feedwater tank
SITE SPOTLIGHT
EDITORIAL 43
out with a concrete lining, which extends to the level
of the polar crane; it fulfills an additional shielding
function and serves to provide fragment protection.
The concrete shell of the secondary containment,
which completely encloses the primary containment,
serves as the second safety barrier. A differential
pressure regime is maintained between the steel
pressure shell, the cavity, and the surroundings. The air
pressure in the cavity between primary and secondary
containment is lower than that in the primary containment
and the surroundings. The cavity thus fulfils
a barrier function to prevent the escape of air-borne
contaminants. The secondary containment is designed
to prevent external man-induced events affecting
the primary loop, and is equipped with a separate
ventilation system.
The concrete jacket of the secondary containment
consists of a foundation slab, a cylindrical concrete
envelope, and a dome. A gas-proof steel liner seals the
inside of the containment jacket.
A thick, cylindrical, reinforced concrete jacket known
as a biological shield surrounds the core of the reactor
pressure vessel (RPV). This biological shield acts as a
shield against the neutron and gamma radiation
emerging from the reactor pressure vessel when the
plant is in operation.
The primary water circulating in the RPV and in the
whole primary loop serves as the moderator and
coolant for the reactor core. The RPV consists of the
RPV upper head and RPV lower segment. The RPV
lower segment consists of a cylindrical vessel with a
hemispherical lower head. The RPV contains the
reactor core with the upper and lower reactor
assemblies, control rods, the thermal shield, and the
incore instrumentation tubes.
Two inlet, two outlet, and two safety injection nozzles
are welded into the lower segment of the RPV. These
connections with the remaining components of the
primary loop are all at the same level. They are
arranged above the reactor core so that the primary
water cannot drain down to the reactor core when a
leak occurs in the main coolant pipes. The inlet nozzles
take the form of diffusers (conical). The ingoing
primary water flows downward along the vessel wall
and thermal shield, then flows upwards through the
reactor core, absorbs heat, and leaves the RPV through
the outlet nozzles towards the steam generator. The
upper head of the RPV has feedthroughs for the
control rods and for instruments and measuring
equipment.
The RPV is made of a low-alloy carbon steel, which is
heatproof, tough, easily welded, and has low radiation
susceptibility. The cylindrical part was welded together
from forged rings. The interior surfaces coming into
contact with primary water are lined with a stainlesssteel
cladding.
The steam generators serve as heat exchangers
between primary water and secondary water. The
primary water enters the steam generators via an inlet
chamber, and flows from this inlet chamber through
the U-tube heat exchangers, releasing the thermal
energy, before reaching the outlet chamber. From
here it is fed to the main reactor pump. In the secondary
section of the steam generator, the water/steam
mixture of the secondary water undergoes a twostage
separation. The separated, dried live steam is fed
to the steam turbines.
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EDITORIAL 44
The main reactor pumps pump the primary water
which has been cooled in the steam generators back
into the RPV. The pressurizer is a cylindrical vessel
partially filled with water whose task is to keep the
A twin-unit plant
Although the two units of the Beznau nuclear power
plant are two independent power plants each with its
own operating license, they are structurally interconnected
and from the outside they look as if they
are a single building complex. Inside the parts of the
building with a controlled zone, the two units are
spatially separate from each other and have their own
technical systems. Each has all the structures, systems,
and components required to facilitate their independent,
safe, and economic operation.
The two units share some facilities and the infrastructures,
and the organization in particular. These
shared facilities generate synergies when the plant is
in operation, but will have to be taken into account as
necessary in the future shut down.
A distinction must be made between security systems
and operating systems. Some systems have mechanical
and electrical interconnections which allow
system functions in one power plant unit to be
supported by the other unit. A small number of operating
systems are located in one unit and fulfill the
functions for both units.
The interconnections between the security systems of
the two units are not required during normal power
generation. To control certain malfunctions events,
operating pressure in the reactor cooling system
constant, and it is connected to the reactor cooling
system via an equalizing pipe.
however, security functions of the other power plant
unit can be accessed via interconnected security
systems. Interconnected operating systems which are
present in both units serve to enhance the availability
or flexibilization of the operation.
The 3 nuclear units (Unit 1, Unit 2 and the interim
storage facility (ZWIBEZ)) on the site also share other
infrastructural elements.
They are surrounded by a shared security perimeter.
The nuclear facilities furthermore have access to
shared infrastructure facilities such as communication
systems, conventional waste disposal facilities, laboratories,
workshops, office buildings, and the staff
restaurant. As Units 1 and 2 are being decommissioned,
the technical systems and organization of
ZWIBEZ will be made autonomous.
The two power plant units likewise share some aspects
of their organization. For organizational purposes, the
operational staff are assigned to one of the two units,
although they can easily move between the two
units because the designs of the units are largely
identical and such swaps are also permissible under
the terms of the license. The other departments
involved in the plant organization provide services for
both units.
Important upgrades and the most recent safety report
Ever since the two power plant units were first
constructed and commissioned, Axpo has con tinuously
improved plant safety by upgrading its technical
safety. In 1992 and 1993, a separate, bunkerized
emergency system was installed for each of the two
units. The emergency system is designed to switch off
the reactor should an «external event» occur and
remove the decay heat of the reactor core. The steam
generators in Unit 1 were also replaced in the same
period. This led to an increase of around 2 % in the
electric power output without any modifications to
the reactor design. The upgrade also encompassed the
installation of the filtered pressure relief system in the
two containment buildings. The steam generators in
Unit 2 were replaced in 1999. The reactor protection
and control system was replaced completely in 2000
and 2001.
Three further major upgrade and replacement
projects followed between 2010 and 2015. The upper
heads of the reactor pressure vessels in both units
were replaced. In a further project, two emergency
diesel generator buildings each with two emergency
diesel generators were built on the site, and took
over from the previous emergency power supply
which had come from the nearby hydroelectric power
plant in Beznau. In addition, the IT system for the
plant was completely renewed.
Of great strategic relevance was also the safety report
for the Unit 1 reactor pressure vessel in 2016. In June
2015, findings made in the material of the reactor
pressure vessels at the Doel 3 and Tihange 2 nuclear
power plants in Belgium led the Swiss Federal Nuclear
Safety Inspectorate (ENSI) to demand that the two
reactor pressure vessels at the Beznau Nuclear Power
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SITE SPOTLIGHT
EDITORIAL 45
Contact
Plant be checked. The inspections carried out found
material inclusions in a small section of the RPV of Unit
1, which had arisen during manufacture.
On November 14, 2016, Axpo submitted the documentation
relating to the characterization and
assessment of the findings in the base material of the
reactor pressure vessel of Beznau Unit 1 to ENSI. This
safety report proved that the safe operation of the
plant is guaranteed and that all safety objectives are
met. Unit 1 was shutdown for a further two years
before ENSI issued a restart permit, and power generation
recommenced on March 19, 2018. The Beznau
nuclear power plant set international standards
with what were probably the most comprehensive
inspections concerning the RPV. Experts of international
renown were consulted, and specialist companies
and organizations were involved in the
collaborations.
Axpo Group
Parkstrasse 23
5401 Baden, Schweiz
info@axpo.com
www.axpo.com
@company/axpo-group
@axpo
@AxpoCH
Beznau – a model plant for the whole world
In fall 2020, the Director General of the International
Atomic Energy Agency IAEA, Rafael Grossi, visited
Beznau nuclear power plant. He was informed about
the continuous upgrades and nuclear safety improvements
in the plant, a general requirement which had
been adopted in the Vienna Declaration on Nuclear
Safety of February 2015.
As has been explained above, Beznau nuclear power
plant has realized several major upgrade projects from
the 1990s to the present day. The safety standard of
the plant was thus brought up to that of a new plant
and aligned therewith. This was mirrored in Grossis’
assessment, which was published on the website of
the Swiss Regulatory Authority ENSI: «The various
safety upgrades at the Beznau Nuclear Power Plant
reflect the longstanding Swiss safety culture enshrined
in the principle of continuous improvement of nuclear
safety. We look forward to Switzerland continuing to
share this important experience with its international
partners.»
About Axpo
The Beznau nuclear power plant is part of Axpo’s pool of power plants. Axpo is the largest Swiss producer of
renewable energy and an international leader in energy trading and the marketing of solar and wind power.
5,000 staff combine experience and expertise with a passion for innovation. Axpo develops innovative power
solutions based on state-of-the-art technology for its clients in 30 countries in Europe, North America and Asia.
Axpo has an environmentally friendly pool of power plants with largely CO 2 -free energy production.
Antonio Sommavilla, Sara Tania Mongelli and Daniele Dagani
Site Spotlight
Beznau Nuclear Power Plant – Decades of Safe, Environmentally Friendly Power Generation
atw Vol. 66 (2021) | Issue 2 ı March
46
DECOMMISSIONING AND WASTE MANAGEMENT
The Other End of the Rainbow:
Nuclear Plant End-of-Life Strategies
Edward Kee, Ruediger Koenig and Geoff Bauer
This article is part II of a 3-part series on challenges, opportunities and lessons-learned related to nuclear in the circular economy. Topics:
I Nuclear New Build – How to Move Forward (atw 1/2021)
II Nuclear Plant – End-of-Life Strategies
III Circular Economy – Lessons Learned, from and for Nuclear
Introduction Nuclear plant “end-of-life” – and decommissioning in particular – is a topic that is changing from a
practical challenge and learning experience in individual cases to a key programmatic challenge to the nuclear
industry as a whole and, as we intend to show in this article, with high relevance for the entire new energy system.
Existing nuclear power plants are
reaching the end of their operating
life and preparing for final closure.
Operating plants with decades of
potential useful life are being closed
early, especially in the U.S. and Europe
for technical, political, and even
financial reasons.
And while a growing number of
nuclear power plants are leaving the
market, the IPCC 1
and many others
see a large and critical role for nuclear
energy to help meet global energy
decarbonization pathways. Yet
although nuclear power is beneficial
for decarbonization, negative public
and political views of nuclear power
are linked to unresolved nuclear
power plant end-of-life issues. For
In addition to the challenges discussed in this article,
further important end-of-life issues include:
p A nuclear power plant decommissioning is a huge
logistical undertaking with constraints from limited
space for lay down areas, temporary structures as
well as challenging transport infrastructure.
p Reuse or disposal of non-radioactive materials, including
large volumes of conventional waste which exceed
normal market volumes and may face public resistance
for transportation and acceptance at landfills due to
their ‘tainted origin’.
p Availability of qualified resources in a “dying” market.
p Different options and interests for subsequent site use
and resultant requirements for the D&D process and
end-state. Including questions how to replace the
functional role of the former nuclear plant (site) in the
electrical supply system.
These are outside the scope of this paper but will be
revisited in future analysis.
example, the “ nuclear waste question”
has led to the exclusion of nuclear energy
in the EU Taxonomy for Sustainable
Finance & EU Green Bond Standard,
at least initially: 2
“The Taxonomy Regulation reflects a
delicate compromise on the question of
whether or not to include nuclear energy
…. While nuclear energy is generally
acknowledged as a low- carbon energy
source, opinions differ notably on the
potential environmental impacts of
nuclear waste. … the Commission has
decided to request … a technical report
on the ‘do no significant harm’ aspects of
nuclear energy.”
The significant end-of-life issues 3
for a nuclear power plant can be put in
four categories:
p Decommissioning (“D&D”) of the
facilities;
p Treatment and packaging of radioactive
waste;
p Long term interim storage of radioactive
waste;
p Disposition of radioactive waste.
The nuclear power industry, and the
authors of this article, consider all but
one of these end-of-life issues as resolved
for commercial nuclear power
plants globally, in principle: the remaining
open issue is the permanent
disposition of radioactive wastes 4 .
This issue remains open for political,
not primarily technical reasons.
However, the lack of a path for
permanent disposition of radioactive
waste affects the entire end-of-life
strategy (including the associated
financing/funding arrangements) for
nuclear power plants 5 . The ultimate
total cost of waste management is
uncertain because the specifications
for waste form and packaging and the
amount of funds/financial assurance
needed to meet these costs are subject
to considerable uncertainty over a
long period of time. Until a permanent
disposition solution is agreed, longterm
interim storage is needed; and
without centralized off-site interim
storage, nuclear power plant sites
become de-facto waste storage facilities
under the oversight of nuclear
safety regulators.
Decommissioning is the one
category that might be considered
relatively self-contained, under the
control and sole responsibility of the
owner/operator. It has a high project
complexity and cost and is the gateway
to subsequent waste management and
disposal as well as to re-use of the site:
p for the existing nuclear power
plant owners and investors who
want to understand and manage
D&D responsibility including the
requirements to set aside funds to
meet these eventual costs;
p for the public, and government/
regulators, who want assurance
that nuclear power plant D&D is
done properly and cost-effectively;
and
p for proponents and developers
of (future) nuclear new build, who
require clarity on the D&D
approach that will allow them
to factor D&D costs into project
financing considerations.
1 E.g., see https://www.ipcc.ch/sr15/chapter/spm/spm-c/spm3b/ or https://www.ipcc.ch/sr15/chapter/chapter-2/2-4/2-4-2/2-4-2-1/figure-2-15/
2 See https://ec.europa.eu/info/sites/info/files/business_economy_euro/banking_and_finance/documents/200610-sustainable-finance-teg-taxonomy-green-bondstandard-faq_en.pdf#page=9&zoom=auto,-12,426
– Technical Reports by two EU bodies are expected in February 2021 i.e. between writing and publication of this
article.
3 In this paper we shall refer to ‘decommissioning’ and ‘D&D’ interchangeably as the onsite Deactivation, Decommissioning, Decontamination and Demolition
programme versus ‘end-of-life’ as the holistic challenge.
4 Some countries have no operational disposal sites for any waste forms (not even LLW), a small number of countries are close to complete solutions, many have some but
not all. – A separate topic is legacy issues at old research, experimental, or military sites and their special, highly demanding technical and environmental challenges.
5 In reflection of this, most countries have established a public domain responsibility for disposal. Most recently, for example Germany in 2017 established a 3-pronged
back-end structure, where utilities retain risk and responsibility (incl. liability) for decommissioning and waste treatment but transferred risk and responsibility for
interim storage and disposal to Government, against cash payment of a fixed “price” based on the estimated cost plus a risk premium.
Decommissioning and Waste Management
The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer
atw Vol. 66 (2021) | Issue 2 ı March
From a technical perspective, nuclear
decommissioning has become a
well-established practice. But as a
large and growing business, new
approaches to decommissioning must
be and are being developed.
So, getting the end-of-life strategy
right is a significant, immediate
challenge for existing nuclear power
plants. Meeting this challenge also is
one precondition for nuclear power to
gain public acceptance and give confidence
to investors and regulators
in the business case for new build
projects, thereby enabling it to help
secure future zero-emission energy
supply.
This article is focused on the issues
related to D&D for commercial nuclear
power plants. 6 Looking at the magnitude
of nuclear power plant closures,
how the nuclear power and decommissioning
industries are changing,
and on best practices for funding
nuclear end-of-life liabilities, we try to
gain insights on where this might
lead for current and future market
participants.
Part I –
Scope of the problem
Ageing plants. Lifetime
extension versus early closure
As the global nuclear power plant
fleet ages, end-of-life strategies attain
increasing importance for the industry
overall. The life extension of
existing nuclear power plants has the
potential to provide large benefits
from a reliable electricity supply with
zero carbon emissions.
In principle, nuclear power plants
are designed for long operating lifetimes
and have the technical capability
to substantially extend their
licensed design lifetime. For example,
most U.S. nuclear power plants have
received approval to operate for 60
years, some have applied to operate
for 80 years, and the U.S. Nuclear Regulatory
Commission has started considering
the issues that may arise in a
100-year operating life.
Common wisdom has it that once a
plant has been fully depreciated it is
highly attractive due to relatively low
generating cost. Certainly, the cost
and risk of extending the life of an operating
reactor are lower than the cost
and risk of building a new one.
| Figure 1
Age profile installed capacity. https://pris.iaea.org/PRIS/WorldStatistics/OperationalByAge.aspx
| Figure 2
Nuclear installed capacities for different lifetime scenarios. From https://www.iaea.org/topics/nuclear- power-and-climate-change/
climate-change-and-nuclear-power-2020
The IAEA states
“… extending the operational lifetimes
of existing NPPs is expected to continue
to deliver significant short to medium
term contributions … this can be
realized with a modest investment to
replace and refurbish major components
to ensure plant operation in line with
current expectations. … lifetime extension
projects are less capital intensive,
feature significantly shorter construction
and payback times, and have a
good track record in terms of cost control
and limiting construction delays.” 7
Yet despite offering important
public goods and being financially
more favorable than nuclear new
build, not only is lifetime extension
oftentimes not implemented but some
plants are shut down early. Besides
political and technical issues, reasons
for this are that in the age range of
25 –35 years, the plant owner may be
faced with decision points related to
some or several of the following
factors:
p A nuclear power plant may, due to
various reasons, cease to have an
assured revenue source, leading to
lower and riskier profits. This
might be caused by privatization or
divestment of government or regulated
nuclear power plants. It also
may be caused by the expiration of
power contracts that provided
revenue assurance. 8
p A merchant generator that relies
on revenue from sales into electricity
markets faces significant
financial risk. In new electricity
markets, some combination of
wind and solar generation and
lower fossil fuel prices may mean
that nuclear power plants face
additional grid requirements (e.g.,
load following) and lower and
uncertain offtake volumes and/or
electricity market prices. In some
DECOMMISSIONING AND WASTE MANAGEMENT 47
6 In this paper we look at decommissioning of commercial nuclear power plants (versus other nuclear facilities), and in the context of “planned” decommissioning
( versus special considerations for one-off projects as in the past or situations due to unexpected economic, technical, regulatory, or political action).
7 See https://www.iaea.org/topics/nuclear-power-and-climate-change/climate-change-and-nuclear-power-2020
8 In the UK, this might happen when a limited term Contract for Difference (“CfD”) ends. In the U.S. most merchant nuclear power plants had a transition power contract
that expired at the end of the plant’s original 40-year NRC operating license.
Decommissioning and Waste Management
The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer
atw Vol. 66 (2021) | Issue 2 ı March
DECOMMISSIONING AND WASTE MANAGEMENT 48
| Figure 3
Financial Impact of early closure (schematic).
wholesale electricity markets, current
or projected revenues may not
even cover nuclear power plant
generating costs.
p Continued operation, whether
under current operating license or
an extended license may require
investments for retrofits, upgrades,
or regulatory requirements. While
these investments are lower than
nuclear new build, they must
compete for corporate commitment
against other investment
oppor tunities that may be more
attractive to financial and other
stakeholders.
p To the extent that D&D can be
completed early and successfully,
or liability and responsibility for
future decommissioning activity
can be transferred off balance
sheet to another party, the early
and immediate closure of a nuclear
power plant may even serve to
improve the owner’s market
valuation (debt/equity ratios
and similar metrics, as shown in
Figure 3).
In such cases early closure can enable
reallocation of investment needs,
reduce further liability accrual and
perhaps even avoid financial operating
losses. This would likely be viewed
favorably by investors, ratings agencies
and other market participants and
should in turn reduce cost of capital
and support other investment opportunities
on better financing terms in
subsidized or lower revenue risk
generation.
One case study for these considerations
is Kewaunee, a U.S. merchant
nuclear power plant operating in a
market-based electricity industry. 9
The other reason that nuclear
power plants are closing is that some
countries have implemented plans to
reduce or phase out nuclear power,
regardless of the plants' age, performance,
or of financial outcomes
and effects on climate. Germany is
the largest example of this; earlier
examples were Italy and the closure
of Soviet-era nuclear power plants
in central European countries as a
condition of EU accession. The recent
closure of the Fessenheim nuclear
power plant in France is a similar
case.
Transition to end-of-life
The global nuclear power industry
has already gained significant D&D
experience, with nearly 200 commercial
plants having closed. This D&D
experience was generally in one-off
D&D projects, where a nuclear utility
was engaged in D&D at one or a few
units in the context of a continuing
operating fleet and where speed,
efficiency, and cost were not always
primary considerations.
In the meantime, nuclear power
D&D is developing into a major
industrial prospect (see Figure 5):
75 % of the over 440 nuclear plants in
operation are at an age above 25 years;
50 % older than 35 years. By comparison,
of the app. 190 plants that have
been shut down already, nearly 75 %
reached an age of 40 years.
CASE STUDY – U.S. Kewaunee nuclear power plant.
The Kewaunee nuclear power plant is a 574 MWe PWR owned and operated by
regulated utilities in Wisconsin. The plant started operation in 1973. In 2005,
Kewaunee was sold to Dominion Resources as a merchant nuclear power plant. The
sale included a Power-Purchase-Agreement (PPA) that expired in December 2013.
The Dominion Resources plan was to invest in the plant to reduce costs, increase
reliability, increase output levels, and increase operating life. The expectation
was that the value of nuclear electricity would increase over time, making this a
profitable long-term investment. After the purchase, Dominion Resources applied
for and received approval from the NRC to operate Kewaunee until 2033.
As the Kewaunee PPA neared the end of its term, Dominion Resources could not
find a replacement PPA and would be forced to sell Kewaunee’s output into shortterm
electricity markets at very low prices (i.e., due to low natural gas prices, low
demand growth, increased penetration of subsidized renewable generation, and
other factors). Faced with the prospect of operating the plant at a financial loss,
Dominion Resources closed the plant on 7 May 2013.
Lessons from this early closure, and other U.S. early closures of merchant nuclear
power plants, is that depending on uncertain short-term electricity markets for
revenue may mean financial losses that make closing the nuclear power plant early
the best option.
Because Kewaunee was closed after 40 years of operation, the plant’s D&D fund
was large enough. A “younger” merchant nuclear plant might impose a large
financial obligation on the owner if the plant was closed early and the D&D fund
was not adequate.
| Figure 4
Kewaunee Case Study.
| Figure 5
Age profiles of global nuclear fleet.
9 More on this is covered in Edward Kee’s new book, “Market Failure – Market-Based Electricity is Killing Nuclear Power“ available at: Market Failure.
Decommissioning and Waste Management
The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer
atw Vol. 66 (2021) | Issue 2 ı March
This means that an increasing
number of nuclear power plants are
reaching the point where they may
have a short time only left to prepare
for end-of-life D&D activity. Besides
the necessary technical and regulatory
preparations, they reach the
point where they are about to make a
transition from accruing funds to pay
for eventual end-of-life D&D activity
to using those funds to meet actual
D&D costs incurred.
Furthermore, nuclear power
companies will have to either transform
their organization and workforce
from nuclear power plant
operations to D&D activities or
address the issues related to outsourcing
the D&D activity to another
company. It is worth noting that a
nuclear power plant entity (at site and
corporate level) will need to undergo
at least three organizational transformations:
p First, transition from an Operation
& Maintenance Organization
with a strict culture of maintaining
a stable system, to a Project
Management Organization that is
challenged to develop and prepare
plans for a large, complex, and
dynamic project usually in a
VUCA 10 environment.
p Then, once the D&D project is
underway, this organization needs
to be skilled in “waste production
factory” operations.
p Finally, when the D&D project
nears completion, this organization
will need to disperse, perhaps
leaving behind a surveillance
stewardship.
Such organizational development and
project skills are important for a
successful D&D programme but are not
usually core competencies of nuclear
power plant owner/operators.
from the government or from ratepayers
that would ensure that all
commitments, including D&D, were
met. This approach was generally
considered “fail safe”. However, merchant
nuclear power plants rely on the
balance sheets of owners, on current
and project profits from operation,
and on dedicated D&D funds. New
merchant entities involved existing
nuclear power plants which had accumulated
funds for D&D activities, but
may not have accumulated enough to
meet regulatory or arms-length
requirements. In some instances, the
new owner of the merchant nuclear
power plant was required to make
funding commitments to make up the
difference.
For example, when the U.S. NRC
considered the transfer of nuclear
power operating licenses from regulated
utilities (i.e., with assured
re covery of costs) to private companies,
they considered the issue of
financial responsibility for long-term
D&D obligations and developed an
approach to verify this based on
detailed and regular reporting of D&D
funding assurance by the nuclear
power plant owner/operator prior to
plant closure.
Criteria for nuclear new build
The new electricity industry structure
involves the potential for new nuclear
power plants that would be merchant
nuclear power plants.
Nuclear new build has generally
not proven to be an attractive business
proposition for (private) investors
in liberalized energy markets 11 ,
especi ally when there is no level
playing field with large subsidized
sectors and/or competition from lowpriced
natural gas supplies and volatilty
associated with renewable energy
sources. The financial investment case
may also be burdened by the approach
to funding end-of-life D&D costs.
Although the ultimate disbursements
for D&D and sub sequent waste
management and disposal are far in
the future, the advance funding
contributions payable during operations
have a negative impact on cash
flow and need to be considered in the
planning phase.
Investors in new merchant nuclear
power plants will look for certainty
on:
p How funds to meet eventual D&D
and waste management/disposal
costs will be accumulated and
secured, in different scenarios,
over the plant lifetime;
p What future changes in end-of-life
costs influenced by Government
and regulatory action (e.g., for
radioactive waste disposition)
should be expected and how will
these be allocated; and
p How risk and responsibility for
high-level waste will be transferred
to Government at end-of-life; since
laws can be changed, this should
be secured by contract.
p How to plan and execute the future
decommissioning in the most
efficient way, given that a nuclear
plant operator may not be best
qualified to manage a complex
D&D project and that after plant
shutdown it may not be best
suited to maintain suitable nuclear
qualifications
DECOMMISSIONING AND WASTE MANAGEMENT 49
Part II – Industry changes
Nuclear project structures after
electricity market reforms
The reform and restructuring of
the electricity industry led to new
business models for nuclear power.
New merchant nuclear power plants
were created by the privatization of
government-owned nuclear power
plants (e.g., UK) and the deregulation
and divestment of regulated nuclear
power plants (e.g., U.S.).
Previously, regulated nuclear
power plants had access to funding
| Figure 6
Nuclear Power D&D paradigm shift.
10 Volatile, Uncertain, Complex, Ambiguous
11 See our article in atw 01/2021 https://www.yumpu.com/en/document/read/65168156/atw-international-journal-for-nuclear-power-012021/09
Decommissioning and Waste Management
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atw Vol. 66 (2021) | Issue 2 ı March
DECOMMISSIONING AND WASTE MANAGEMENT 50
The public needs certainty:
p That the owner/operator will
establish technically competent
operations and waste management
to minimize radiological and
other environmental risk and cost
related to D&D activities;
p That financial and human
resources will be available to
complete D&D activity, as opposed
to a company that will “disappear”
at the end of nuclear power plant
operating life; and
p That the plant owner will have the
financial and human and technical
resources and competencies to perform
plant closure and all related
responsibilities in accordance with
all public good requirements: (a)
those relevant to closing the
relevant plant as such; (b) those
relevant to the contributions the
relevant plant was expected to
make towards overall industry
needs (e.g., funding disposal sites)
during longer continued operation.
12
Special considerations apply for both:
p What happens in case of early
closure, when the plant has not
earned sufficient income to fund
the shutdown costs 13
p How is D&D funding for plants that
close early resolved, perhaps with
different approaches based on the
cause of early closure:
P Owner’s responsibility (e.g.,
operating error)
P Regulatory action (e.g., new
safety requirements),
P Government action (political
“exit” decision)
P other Acts of God
Depending on the answers to these
questions, or lack thereof, a positive
investment decision may not be
possible.
In recognition of these challenges
for nuclear new build, the United
Kingdom has put in place legislation
and contractual arrangements that
consider domestic lessons learned and
international best practices. Per a
Funded Decommissioning Programme
the owner/operator is required to set
aside some of the revenue from plant
operation (i.e., under a 35-year
Contract for Difference (“CfD”) for
Hinkley Point C) for back-end costs.
The funds set aside are ringfenced in a
bankruptcy remote vehicle and both
their ade quacy and appropriateness
is subject to regular independent
review. The condition, price and terms
for transfer of the wastes remaining
after decommissioning to Government
are contractually agreed.
Since the CfD strike price reflects
these costs, and because there are
mechanisms to re-open the CfD at
defined future points, they are passed
along to electricity users. It is unclear
how D&D funding would be collected
for a new merchant nuclear project in
the U.S. or other countries.
This discussion focused on private
investment in merchant plants, as the
issues are most pronounced in this
context. Nevertheless, similar considerations
apply in case of publicly
owned new build programmes, and
certainly should serve as benchmarks
for other models (classic rate-based or
e.g., PPAs, CfD, RAB).
New decommissioning
approaches
Industry experience so far has considered
three scenarios for managing
end-of-life D&D liability:
p The owner self-performs, with
suitably specialized subcontractors
for various purposes. This is the
tradi tional approach. It is certainly
an efficient solution when there
is a sufficiently large D&D programme,
but if that is the case then
it can still be a significant distraction
from “core business”.
p The owner transfers responsibility
to a third-party turn-key
contractor but retains ultimate
liability. When this has been tried
at commercial nuclear power
plants, it typically resulted in contractors
experi encing cost overruns,
passed on to the owner, and
the owner, in retrospect might
have been better off self-performing.
Prospects for improvement
exist as industrial and
regulatory experience with decommissioning
grows and future risk
of failure is bounded.
p A third party steps in and takes
over full responsibility and
non-recourse liability from the
owner. Traditionally, this has not
been accepted by regulators for
fear that the third party would
(perhaps even by design) not have
the same financial strength, the
same ability to post acceptable
third-party financial assurance
(e.g., letters of credit) or the ability
to correct any shortfalls in ringfenced
funds 14
set aside during
operations. As a result, and as
noted above, owners have therefore
not typically been able to fully
discharge liability. However,
recently efforts have been made
that promise to overcome these
hurdles.
As a major reference for the first of
these three scenarios, this is the
approach (still) being applied by the
four nuclear utilities in Germany, each
of which has a substantial decommissioning
programme underway, spread
across several sites in several federal
States, and with some units still in
operation. It remains to be seen
whether, individually or collectively,
they will consider new decommissioning
business models once the
entire fleet is shut down from 2022
onwards: this would be politically
highly challenging, but there could be
strong benefits.
The second scenario might be
considered a compromise between the
first and the third; it is quite common
at Government owned sites. The third
scenario has been gaining traction in
the U.S. market, where several companies
have focused on purchasing
nuclear power plants as they close,
with the transaction transferring the
entire plant and site along with
the NRC license, the D&D funds, the
responsibility to complete the D&D
funds:
p The old utility owner can shift the
entire plant and long-term D&D
responsibility to another party,
with the benefits noted above.
p The new owner: where, as an engineering
company or services provider
they could capture only a
relatively small portion of the total
decommissioning budget, at competitive
margins, the new “D&D
company” has a captive market
(its own nuclear power plant) for
its D&D capabilities, controls the
entire budget and funds, and has
the potential for profits if the D&D
activity is completed in a timely
and efficient manner.
12 E.g. it may seem that in the Unites States early closures are leading to shortfalls in expected accruals for the national high-level waste disposal fund:
https://www.forbes.com/sites/jamesconca/2021/12/29/premature-nuclear-reactor-retirements-could-effect-nuclear-waste-disposal/?sh=7044de5e6ab4
13 Noting precedents such as Mülheim-Kärlich (Germany) or Shoreham (USA) where plants were shut down shortly after criticality, i.e., incurring not only complete asset
write-off but also full decommissioning cost: in one case at the cost to the owners in Germany, in the other as a pass-through to ratepayers in New York.
14 Typical practice in the US and Western Europe is for owners/operators to accrue funds (through cash contributions and capital market investment returns on these) in
advance of decommissioning, which are then subsequently drawn upon to meet these end-of-life as and when they occur. To mitigate risks associated with operator
insolvency, these funds are usually ring-fenced from the operator. More detail on this aspect is provided in Part III.
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atw Vol. 66 (2021) | Issue 2 ı March
p The regulator might accept that
the new owner is in a better position
to perform the D&D in a safe,
timely and compliant manner.
Market players specializing in
this approach in the U.S. include
Accelerated Decommissioning Partners
(a joint venture between North-
Star and Orano), Comprehensive
Decommissioning International (a
joint venture between Holtec and
SNC-Lavalin), and Energy Solutions.
Whether such third-party approaches
are transferable to other D&D
programmes, in the U.S. or internationally;
and if so, in which situations
and under what con ditions they
would be possible and beneficial, is
beyond the scope of this article.
However, at least in theory an
industrial offering of a sustainable
“decommissioning business model”,
with com panies with sufficient
financial means (deep pockets and
security) and broad technical and
project specialization could prove
beneficial for nuclear power plant
owner/operators and for the common
good. Such industrial D&D companies
could bring experience and a
pipeline of D&D projects that would
enable:
p Economies of scale and learning in
D&D activity;
p A sustainable long-term business
model with employee retention and
growth potential;
p Incentives to develop new and
improved techniques and equipment
for D&D activity;
p Better capital market allocation and
lower risk, with nuclear utility assets
unlinked from D&D risk and D&D
specialist company risk spread
across a portfolio of projects.
A critical enabling factor for such a
business model is that decommissioning
liabilities are well funded, with this
funding available as and when needed:
in adequate amount, liquidity, and
security.
Part III – Best practice for
funding end-of-life costs
As the nuclear power and D&D
industry are changing, there are some
lessons about how to fund and finance
D&D costs.
Historical context
There are different ways – in theory
and practice – how a nuclear power
plant can collect the funds to meet the
| Figure 7
Financial profile over nuclear plant lifecycle.
eventual costs associated with longterm
end-of-life activity.
Historically, many countries had
the government take responsibility for
meeting the future end-of-life costs,
typically leaving taxpayers to fund
these activities as and when they
occur. This was easy when the
government was also the developer
and owner of nuclear power plants in
the country. The problem with this
approach is that it is contrary to the
principle that cost should be allocated
where it is caused (“polluter pays”)
and leaves the liability to future
generations. In case of industry
privatization, a further downside of
this approach is that the government
position may change over time
and a nuclear power plant owner
would want a clear way to ensure
that these liabilities do not come
back to them.
For these and other reasons, nowadays
most countries apply some combination
of the following approaches,
albeit not yet generally in line with a
common “gold standard”:
p Government responsibility, with a
D&D tax/fee charged during a
nuclear power plant’s operating
life (e.g., like the U.S. spent nuclear
fuel fee and the resulting large and
unspent nuclear Waste Fund 15 held
by the U.S. Government).
p Plant owner responsibility to set
aside funds during the plant’s
operating life to be used to meet
future D&D and waste management/disposal
costs.
p In practice, these funds may or may
not be ring-fenced, available for
financing other activities, insolvency
proof.
p The closest analogy are the various
types of retirement or pension
DECOMMISSIONING AND WASTE MANAGEMENT 51
15 This led to lawsuits that stopped the spent nuclear fuel fees because the US government had breached its contract to take spent nuclear fuel and had not been able to
develop a viable permanent disposition approach.
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The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer
atw Vol. 66 (2021) | Issue 2 ı March
DECOMMISSIONING AND WASTE MANAGEMENT 52
funds. The main, significant
difference is that the underlying
obligations, funding and risks for
future nuclear back-end liabilities
cannot generally be effectively
transferred to the insurance
market.
Depending on how such a retention
were structured, this might be a passthrough
to ratepayers or affect the
plant cash flow and return on investment
(making nuclear investments
electricity less attractive). Even with
such approaches there is a risk that
the accrued funds might not be available
when needed (e.g., in the case of
earlier than planned decommissioning,
or due to operator insolvency,
or State budget policy) or that they
might not be adequate (e.g., due to
cost escalation or underperformance
of the investments held in the fund).
Best practice
The best practice for meeting future
end-of-life costs should be some form
of advance funding arrangement
during the operational phase, with
appropriately ring-fenced trust funds
(or similar vehicles) to mitigate the
risk of operator insolvency or other
fiscal diversion of funds. A best
practice framework for managing
end-of-life financial liabilities includes
advance funding and a sound
approach to investment strategy,
supported by ongoing governance,
monitoring and risk management 16 .
In this context, it is critical that the
interfaces between the different endof-life
liability categories and responsibilities
are well defined and agreed,
as outlined in Parts I and II above.
Crucially funding/investment strategies
need to be cognizant of the
interest rate sensitivity (i.e., the long
duration) of future end-of-life costs
and structured in such a way as to best
mitigate this risk. Ideally this should
all be captured within a well-defined
national (or potentially even international)
decommissioning and waste
management liability framework,
setting out clear requirements,
methodologies, and principles for
securing adequate future funding,
investment of these funds, roles and
responsibilities and the broader
approach to governance.
Oftentimes there is a hidden or misunderstood
conflict-of-interest concerning
the objective that these funds
should follow a conservative (low-risk)
investment strategy. This is often
understood to imply using “safe”
instruments, i.e. government notes, for
the majority of the fund’s in vestments.
However, this can inadver tently lead to
a higher risk – namely, that future
funds might not be sufficient, or that
necessary higher future funding commitments
will place too strong a burden
on electricity rates – due to the often
low (and potentially negative real)
yield avail able on these government
bonds. Another con sideration that can
complicate investment policy occurs in
those cases where the funds are to be
invested for other specific politically
desirable benefits.
Ring fenced end-of-life funds
In Figure 8, we outline the key elements
of a best practice framework
that might serve as a benchmark for
ensuring that future end-of-life costs
can be met with a high degree of
confidence in a cost- effective manner.
(a) Estimation of expected
future costs
Recognising the liability-driven nature
of the funds set up to meet the end-oflife
costs, a robust estimate of these
future costs is required before any
realistic consideration of funding and
investment is possible. The NEA, IAEA
and EC’s International Structure for
Decommissioning Costing (“ ISDC”)
has been developed to assist and its
use might well be regarded as best
practice.
It is crucial that cost estimates are
reviewed and updated periodically in
order to ensure both they and the target
level of funds to be accumulated
remain appropriate.
| Figure 8
D&D Liability Framework.
(b) Assessment of the likely
future cost inflation
Setting an assumption for future cost
inflation requires an understanding of
general long-term inflation expectations
and nuclear specific factors.
Government bond market implied
inflation and long-term consensus
forecasts can provide a reasonable
starting point for the former but fail
to capture the latter. A pragmatic
approach of identifying a few major
cost drivers (e.g., labour, energy and
disposal costs) and determining
France
(operators)
UK
(NLF)
Germany
(FNWM)
Spain
(PGRR)
Slovakia
(NNF)
Hungary
(CNFF)
Sweden
(NWF)
Fund value (€m) 45,300 10,973 24,148 5,018 1,399 910 6,839
Operator / owner liability value (€m) 46,600 38,289 13,946 10,971 11,537 2,205 10,522
Market consistent liability value (€m) 67,310 63,621 19,400 18,713 11,537 7,983 12,328
Shortfall not covered
by existing funding arrangements (€m)
| Table 1
2018 EU D&D funding situation.
20,710 25,332 - 7,742 - 5,778 1,806
16 For example, e.g. see our Report to the EU Commission: https://op.europa.eu/en/publication-detail/-/publication/3a94a52a-ec36-11e9-9c4e-01aa75ed71a1/
language-en?WT.mc_id=Searchresult&WT.ria_c=37085&WT.ria_f=3608&WT.ria_ev=search
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atw Vol. 66 (2021) | Issue 2 ı March
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reason able inflation assumptions for
each of these is likely to be appropriate.
Our 2018 review of practices across
the EU 16
found that although some
Member States (e.g., Germany, Sweden
and the UK) make allowance for
expected future decommissioning and
waste management specific inflation,
this practice was not widespread.
(c) Setting investment
objectives, target levels of
return and risk limits
An appropriate rate of expected future
nuclear cost inflation should provide
a minimum for the level of target
investment return. This minimum
level of target return can also then be
used as the discount rate to place a
present value on the expected future
end-of-life costs. The discount rate
can be thought of as the minimum
return that must be achieved on a
fund’s investments each year in order
to meet decommissioning and waste
management costs at the end of the
operational phase without additional
(unforeseen) funding.
In the last decade, interest rates
and the yields available on long-dated
government bond assets (typically
regarded as “risk-free”) have fallen
significantly. In many jurisdictions
this now means that these “risk-free”
rates are not likely to exceed future
inflation. Funds held to meet end-oflife
decommissioning/waste management
costs thus need to accept risk in
pursuit of higher investment returns,
which of course creates the possibility
for investment returns to be lower
than expected. This challenge is particularly
acute since 1) gross investment
returns are likely to be lower in a
low interest rate environment and 2)
current equity market valuations
are high due to economic stimulus
measures (and some would argue
disconnected from fundamentals).
The current low-interest rate
environment (together with the
elevated levels of global equity
markets) is an important consideration.
Lower interest rates lead to lower
discount rates being used to derive the
present value of long-dated future
end-of-life costs. These lower discount
rates reflect the expectation that
capital market investment returns will
be lower in future, which in turn
serves to create funding shortfalls and
the requirement for even greater
future funding commitments. In a
circular economy, the ability for
operators/owners to meet end-of-life
costs effectively, without placing an
undue financial burden on public
finances or future generations, is
crucial to the future of nuclear power
generation.
In the 2018 EU study referred
to above 16 , several Member State
investment portfolios were found to be
dominated by Government bonds and
cash investments and, furthermore,
discount rates in several Member
States were not realistic in light of the
future investment returns that might
reasonably be expected from these
investments (i.e., they had failed to
make adequate allowance for the low
interest rate environment). As shown
below, this suggested material underfunding
in several Member States
which is unlikely to have been rectified.
This “forward-looking” approach
based on likely future inflation and
investment returns applied to plant
specific future cost estimates differs
fundamentally from the US NRC
approach set out in 10 CFR 50.
The latter is a “backward-looking”
approach based on an assumed
historical cost profile with cost escalation
factors to inflate this cost estimate
to the present time. Whilst it does
provide a minimum value against
which to compare the adequacy of
accumulated fund investments, it is by
DECOMMISSIONING AND WASTE MANAGEMENT 53
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The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer
atw Vol. 66 (2021) | Issue 2 ı March
DECOMMISSIONING AND WASTE MANAGEMENT 54
| Figure 9
D&D Liability Framework.
no means clear that achieving this
minimum value will ensure the actual
sufficiency of fund investments to
meet future decommissioning and
waste management costs.
This is already a significant issue
for the US nuclear industry, which is
only likely to increase in importance
(in both the US and elsewhere)
as new decommissioning business
approaches and models come to the
fore. In particular, permanent licence
transfer models (e.g., for Vermont
Yankee, Oyster Creek, Pilgrim) and
the adoption of accelerated decommissioning
approaches can materially
accelerate withdrawals from these
funds, thereby calling into question
previous assumptions regarding
the time available for them to
grow without further funding contributions.
(d) Determining contribution
strategy and funding
milestones
Given realistic assumptions for future
cost inflation and target levels of
investment return it is possible to
calculate the level of contributions that
will need to be made into the fund.
Best practice would then be to
develop an “intended funding path”,
specifying the percentage of the total
liability (i.e., the funding level) that
should be accumulated at different
points in time, together with details
on how any deviations (both upside
and downside) from this intended
funding path will be dealt with, as
shown in Figure 9.
There is an important trade off in
setting the date of fund maturity. On
the one hand, by requiring funds to be
fully accrued at the time when the
plant falls out of rate base or other
support schemes would go a long way
to mitigating the risk of fund shortfalls
in the event of earlier than planned
decommis sioning or where lifetime
extensions are not pursued. Indeed,
this is what is envisaged under the UK
new nuclear build regime. On the other
hand, however, a shorter funding
period results in a greater impact on
ROI, hence making it more difficult to
attract investors.
(e) Developing an investment
strategy
The next consideration is how best to
construct an investment portfolio that
is expected to deliver the required
level of investment return over time
with no more than the acceptable
level of risk. If the investment strategy
cannot deliver the target level of
return, then over time the fund will
start to fall behind its intended
funding path, creating a need for
additional funding contributions or
even higher target levels of return
in future (which may not be commensurate
with the acceptable level
of risk).
Deriving a suitable investment
strategy requires a detailed assessment
of the investable universe and
the expected cost / liability risk profile,
taking full account of:
p Return and risk expectations for
different asset classes;
p Correlations between different
asset classes, diversification benefits
and how both of these might
vary in different financial market
conditions;
p Underlying drivers of risk and
return, including the extent to
which interest rate and inflation
risk can be hedged and the appropriateness
of active management;
p Investment management fees,
liquidity considerations and the
relative complexity inherent in
different asset classes;
p Restrictions or constraints on the
ability to invest in certain asset
classes or individual securities.
Developing an investment strategy is
not a one-off exercise and will need to
evolve over time, in particular:
p In the early years of operations
there are many years until end-oflife
costs are expected to be
incurred. This should provide
greater investment flexibility since
there is little need for immediate
liquidity and a long period of time
to correct any shorter-term
investment underperformance.
p Most of the cash disbursements
related to decommissioning and
waste management occur once
the nuclear facility has stopped
generating revenue. At this point,
accrued funds should not only be
sufficient to meet the expected
future costs but steps should also
have been taken to minimise assetliability
risk. There is significantly
less tolerance for investment risk
given the need to realise assets to
Decommissioning and Waste Management
The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer
atw Vol. 66 (2021) | Issue 2 ı March
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meet cost outgo and given the lack
of recourse to additional cash
funding.
The second bullet above is particularly
relevant given that future decommissioning
work may well be expected
to be carried out by non-utility merchant
operators or specialty decommissioning
companies who may lack
the financial strength typically associated
with traditional regulated utilities
and who are therefore less likely
to be able to provide any further funding
for decommissioning and waste
management.
Capturing details of the strategic
asset allocation, how it is to be implemented
and how it is expected to
evolve over time in a formal policy
document should be seen as a key governance
requirement.
(f) The importance
of ongoing monitoring
and regular reporting/
disclosure
Ongoing monitoring of and regular
reporting on the development of a
fund’s investments relative to its
liabilities (and how this compares to
an intended funding path) is essential
Geoff Bauer
Principal
+44 (0) 20 7178 3647
geoff.bauer@mercer.com
For institutional investors only. Mercer Limited is authorised and regulated by the Financial Conduct Authority.
Registered in England No. 984275 Registered Office: 1 Tower Place West, Tower Place, London EC3R 5BU.
for ensuring that the investment
strategy remains appropriate and that
the fund is able to react quickly in light
of emerging risks or opportunities.
The level of detail and frequency of
monitoring/reporting updates should
be based on the specific circumstances
of each fund and, again, may well
need to evolve over time. In early
years, less frequent monitoring may
be required but the frequency should
be increased as the date of cessation
of operations approaches. This is
consistent with NRC requirements in
the US and the new nuclear build
regime in the UK.
A detailed update of future cost
estimates might only be carried out,
for example, every three to five years.
However, as these cost estimates
should be the primary driver of
funding and investment strategy, it
would be reasonable to expect the
following to be reviewed in light of
any material changes to the future
cost estimates:
p The methodology used to determine
the assumed rate of future
cost inflation;
p Investment objectives, target levels
of return and risk limits;
p The adequacy and appropriateness
of currently agreed funding contributions;
p Strategic asset allocation (taking
account of underlying market
conditions); and
p A Statement of Investment
Principles (or similar policy document).
Putting ‘best-practices’
in context
Actual case studies show that the
funding and investment approaches
adopted by end-of-life funds have not
always been optimal and, whilst
there are examples of best practice
being applied in certain areas and
in certain jurisdictions, 17 there remain
inconsistencies in a number of key
areas. As the nuclear industry matures
and the time period until large
scale D&D activity draws near, it is
critical that these incon sistencies are
addressed.
If they are not, there is an everincreasing
risk of actual funding
shortfalls. Assuming the funds are
sufficiently ringfenced to exclude
solvency risks over an up to appr.
100-year period, which is not always
welcome to brighter
DECOMMISSIONING AND WASTE MANAGEMENT 55
17 Examples where this has been achieved, or at least close to that, are the UK with the FDP for the new build programme, or Germany in the 2016/17 system switch.
Decommissioning and Waste Management
The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer
atw Vol. 66 (2021) | Issue 2 ı March
DECOMMISSIONING AND WASTE MANAGEMENT 56
the case, the funds available would
serve as a financial ‘safety net’ – but
the underfunding would still result in
legacy liabilities being left to future
generations.
On the other hand, with a solid
funding scheme in place, compatible
with best practices outlined here, this
would enable some of the new, fungible
D&D approaches and create an
important building block for the
industry to evolve most efficiently.
Part IV – Where does
the rainbow lead?
The end-of-life D&D activities and
requirements for nuclear power
plants are well-understood in principle,
but much room for optimization
remains while big challenges for
an efficient implementation are fast
approaching.
As these challenges are met, and
nuclear development moves further,
new aspects will need to be factored in
future back-end strategies:
p If future nuclear plants include a
large fleet of Small Modular
Reactors, and in more new
markets: what back-end issues and
opportunities are created (e.g., for
risk sharing and learning)?
p If future nuclear plants include
breeders and other types of
reactors capable of re-using used
fuel and even some waste types:
how is the ‘value’ of their feed
material reflected in the market
model and how does this perhaps
incentivize decommissioning?
p At many sites, there is a 'pot of gold'
at the end of the rainbow. D&D usually
considers the end state from
the perspective of an environmental
liability that needs to be minimized
and restituted, and models
its Programme acoordingly (e.g.
see Figure 7). But instead, the site
may have significant value as an important
asset for future purposes.
Which programme achieves the
integral optimum, maximum residual
value over minimal D&D cost,
with given external parameters?
Strategic goals for plants end-of-life
p Place risk where it is best managed.
p Protect the public at large and local stakeholders
from incompetent or negligent, or insolvent custodians
of future legacy issues.
p Transition the site to new uses. Include optimization
scenarios into the D&D Programme design.
p Achieve economic optimization: Operators do what
they do best: build and operate a new energy system.
D&D champions perform safe efficient timely liability
management.
Taking a step back, and with a
forward- looking view towards future
energy markets:
p Over the next 2 or so decades
the world will be building an
entire new, decarbonized energy
infrastructure, with considerably
larger share of electricity and
requiring new types of energy
services (such a storage, P2X
conversion, smart grid functionalities,
frequency control, etc.)
p In parallel it will be decommissioning
the existing carbon-based
global energy producing and
electricity generating fleet (in the
industrialized world). In addition,
since the new energy system consists
of many shorter-lived assets,
we will also be decommissioning
the first and second and next
generations of wind and solar
farms and other facilities.
p In other words, we will need a
highly efficient industrial structure
to build, operate, and decommission
several trillions worth of
assets in a 20-to-30-year period.
What lessons can be learned from the
nuclear experience for a sustainable
“circular economy” in the electricity
industry and energy markets more
broadly? how can nuclear participate
by addressing its unique end-of-life
challenges? What about the huge
infrastructure building programme
that will be needed to decarbonize
Europe: wind, solar, CCS, hydrogen:
what is the best way to protect the
communities and other stakeholders
against future legacy issues?
We believe it will greatly benefit the
players in the global energy industry,
the governments overseeing this programme,
the ratepayers financing the
effort as well as the communities
hosting the facilities and infrastructure
if we could achieve four things:
p Develop the industrial skills to perform
new build on the one hand and
decommissioning on the other most
efficiently – improving learning
curves and economies of scale.
p Give assurance to new build investors
and the public – including local communities
where new facilities (whether
nuclear or other) are to be developed –
that funds for the future decommissioning
will be adequate and safe.
p Develop a system to ringfence the
cost and secure the funding for the
future liabilities.
p Develop a market, with best-in-class
market participants and suitably
fungible products, to enable smooth,
safe, regulated industrial and economic
division of labor.
We look forward to discussing these
ideas further in a future opinion piece
for atw. We will be happy to reflect
comments which we would like to
invite from readers of this and our
previous article.
Authors
edk@nuclear-economics.com
Edward Kee
NECG CEO, Founder and
Principal Consultant
Nuclear Economics
Consulting Group,
Alexandria, USA
Edward Kee is an expert in nuclear economics. Mr. Kee
provides advice to governments, investors, regulators,
regulated and unregulated electricity companies,
nuclear companies, and other parties.
rk@ruediger-koenig.com
Ruediger Koenig
NECG Affiliated
Consultant,
Interim Manager
and Executive Advisor
Nuclear Economics
Consulting Group,
Essen, Germany
Rudy Koenig supports market players in the clean
energy industrial value chain, structuring complex
business transactions in large capital projects and
managing lean business operations. He has held
executive responsibilities for suppliers in the nuclear
front- and back-end and has helped a large utility
investor develop and ultimately sell several nuclear
new build projects.
geoff.bauer@mercer.com
Geoff Bauer
Principal Consultant
Mercer, London, UK
Geoff is a Principal Consultant and Senior Actuary
focused on the design and implementation of
strategic liability-focused investment, hedging
and risk management strategies for a range of
institutional investment clients. He leads Mercer’s
global efforts with respect to the financing/funding
of various long-dated environmental obligations.
He has advised a large number of Fortune 500 companies,
including energy companies and insurance
companies, as well as sovereign wealth funds, nuclear
decommissioning funds, pension funds and other
institutional investors on how best to control the
financial impact of long-dated liabilities on their key
performance metrics.
Decommissioning and Waste Management
The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer
atw Vol. 66 (2021) | Issue 2 ı March
Ground Control and the Principle of
Minimizing Radiological Exposure as Key
Drivers for the Recovery of Radioactive
Waste Out of the Asse II Mine
Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
Geology The Asse salt structure is located in the Southwest of the Hercynian Mountains in Northern Germany.
In geological times, compressive tectonic movements ruptured the overlying rock strata covering the salt layers of the
Zechstein series deposited 250 million years ago. Consequently, the rheological salt ascended between the layers of the
lower and upper Buntsandstein forming the steep Asse salt structure with 40 to 70 degree dip in the Northern and
Southern flanks. The structure strikes over a length of about 4 kilometers West/ East and is only a few hundred meters
wide across strike at the top of the structure.
| Figure 1
Rise of the Asse salt structure. From left to right: first rupture of the flat deposit by compressive tectonic stress, second lift of overburden strata and rise of salt,
third actual geological setting with blocked overburden and complex and steep salt structure [BGE archive].
The formation of the Asse structure
was quite intense compared to neighboring
structures like the much more
gentle Elm salt structure. The ascent
induced intense tectonic faulting to
the overburden and reduced the
coherence of the rock masses by
breaking the overburden into blocs
(see Figure 1). In addition, the internal
structure of the Asse salt dome
indicates a turbulent and rapid genesis
of the formation. Individual layers
rose at different rates and the
sequence of salt layers within the salt
structure as well as the topography is
now irregular. Characteristic is the
vertical position of anhydrite in the
center of the structure. Anhydrite is
one of the typical geological markers
of the Zechstein salt sequence. At the
surface, you see two separate ridges
with a gentle trough in-between. This
unconformity is another indication of
rupture and discontinuity caused by
the rise of the structure.
The Asse salt dome rose near to the
surface. Therefore, the top of the
structure is close to near- surface
ground water. The overburden at the
Southern flank of the structure has
layers of porous sandstone and fragmented
limestone (see Figure 2).
Consequently the salt structure is
always close to potential aquifers
( water bearing strata), even at depth.
In case the integrity of the salt
structure is compromised, near surface
ground water may enter mineopenings
travelling along aquifers and
faults within the overburden and internal
cracks within the salt structure.
On its path, the groundwater dissolves
salt minerals and turns into brine.
Mining
The specific mining vocabulary
varies between mining methods and
mining districts. Most mining methods
extract valuable minerals by creating
cavities or voids, named stopes or
rooms. They leave pillars to protect
the structural integrity of the
underground workings. Sometimes
horizontal pillars are named roof. In
underground repositories for radioactive
waste, often the term emplacement
chamber describes the rooms
designated for accepting the waste.
This paper uses the terms stope
and pillar when describing the
conventional part of the mine and the
term emplacement chamber for the
stopes, where the waste is stored.
Mining salt from the Asse structure
started in 1906. In total, around five
million m³ of rock salt and potash has
been mined until the 1960s with
the largest mining district close to
| Figure 2
Geological Cross-section showing blocked layers of sandstone and limestone in the overburden of the
Zechstein salt sequence (crosscut from Southwest to Northwest, from left to right) [3].
DECOMMISSIONING AND WASTE MANAGEMENT 57
Decommissioning and Waste Management
Ground Control and the Principle of Minimizing Radiological Exposure as Key Drivers for the Recovery of Radioactive Waste Out of the Asse II Mine ı Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
atw Vol. 66 (2021) | Issue 2 ı March
DECOMMISSIONING AND WASTE MANAGEMENT 58
| Figure 3
Cross-section from South (left side) to North (right side), showing shafts, entries and stopes of the Asse mine within the salt structure
[BGE archive].
the Southern flank of the structure
(see Figure 3).This district contains
131 stopes, each up to 60 meters on
strike, 40 meters across strike and
15 meters high. The stopes are configured
in 12 rows and 9 levels. The
bearing structure of the mining
district close to the Southern flank
consists of 12-meter wide vertical
pillars between the ribs of the stopes
and 6-meter thick horizontal pillars
between floor and roof of the stopes.
In total, the district stretches over
260 meters in height, from 490
to 750 meter below surface, and
650 meters along strike. A 20-meter
wide barrier pillar in the center splits
the mining district into an Eastern and
a Western part, between the fourth
and the fifth row, counted from
the West. The thickness of the salt
barrier between stopes and overburden
rises from only 7 meter at the
top to > 20 meter at the bottom of the
mining district.
Backfilling the mine started in
the 1980s. Up to today a total of
4.4 million m 3 of stopes and entries
have been backfilled. Stopes have
been backfilled pneumatically using
1.8 million m 3 of rock salt material
from mining lower levels and
2.2 million m 3 from waste piles
of neighboring mines. Later on
0.4 million m 3 of remaining voids and
entries have been concreted using
Sorel concrete made of acid-base
cement and rocksalt, a recipe
geochemically stable even in
potash dominated brines. Currently
1.2 million m 3 are still active for
compression, mostly as porous
volume of the pneumatically
backfilled rocksalt. It is planned to
back fill another 0.2 million m 3 of
entries and voids until 2028.
Mining induced Ground
Movement
Basic Principles
An empty stope cannot carry
overburden. Therefore, neighboring
structures have to carry additional
load, as the total load caused by the
weight of the overburden stays the
same. The mining activity redistributes
in-situ stresses and causes
additional stress to the bearing structure
of the mine, namely the vertical
and horizontal pillars. The rock
masses later have a tendency to
homogenize the stress level again by
moving into the stopes.
Movement of the rock masses is
welcome, as it reduces stress peaks in
the close vicinity of the stope and
subsequently the risk of destroying
the structural integrity of the
surrounding rock masses. If well
designed, the remaining high stress
zone does not exceed the stability of
the pillars. The contour of the stope
remains integer, stresses are redistributed
away from the stope and a
new arch is formed further away.
Mechanical roof support structures
out of concrete and steel predominantly
stabilize and reinforce the
contour if needed.
While this interaction of excavation,
stress redistribution and
deformation works in every material,
there are significant differences
between rock types. Hard rock has
little deformation; its strength allows
with standing stress peaks without
breaking. The hard rock accumulates
stress; its brittle behavior may lead to
sudden failure by breaking, if stopes
become too large. Salt like the
Asse material has far less strength
compared to hard rock. Instead, it has
rheological behavior and creeps without
breaking, when homogenizing the
stresses by moving into the cavity. You
may mine large stopes with little
ground support, as the stress/strength
management of salt is quite effective.
If you compare hard rock and salt,
much larger rock mass movement
accompanies the formation of a new
stable stress environment in salt. In a
way, salt follows the principle “the
smarter one gives way”.
For stability of any underground
excavation, it is necessary that the
rock mass movement is declining and
a new stable balance of stress and
strength develops before the cavity
collapses.
Every stability is limited in time; at
the end every void in the deep underground
closes. This behavior of the
rock masses is known as “horror
vacui” of the underground environment.
The mine design stabilizes the
underground workings for the time of
utilization, typically some decades. In
the long run the inevitable closure of
the voids is beside the gas formation
of corrosive processes one of the key
drivers of the mobilization of nuclides
within fluids in the deep underground,
subject to the safety case of
any repository of nuclear waste.
Movement of the Southern
Flank in Space and Time
The bearing structure of the Asse mine
is closely monitored regarding the
deformation of pillars and seismicity.
The intention is to control the rock
mass movement by backfilling in such
a way, that the deformation is as
uniform as possible to prevent new
fluid path to develop. A key indicator
is the horizontal compression of the
pillars. Because the Southern flank
steeply dips, and rock masses typically
move perpendicular to the dip, the
rock masses move largely horizontally
into the mine. Analysis of the data
shows, that 90 % of the pillar
com pression has its origin in the
movement of the Southern flank into
the mine. Only a minor part of the
compression comes from movement
of the central and Northern parts of
the mine into the stopes. Therefore,
compression rates are a good indicator
for the rock mass movement of
the Southern flank.
Decommissioning and Waste Management
Ground Control and the Principle of Minimizing Radiological Exposure as Key Drivers for the Recovery of Radioactive Waste Out of the Asse II Mine ı Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
atw Vol. 66 (2021) | Issue 2 ı March
| Figure 4
Pillar compression rates over time, with indication of different periods of mining, storage and backfilling
[3]-adapted.
Figure 4 shows the trend of pillar
compression rates over time since the
start of the mining activities. The blue
lines represent different measuring
points at different levels in the
Southern mining district. During the
decades of active mining the Southern
flank moved at a constant speed of
well below 10 cm/a into the stopes of
the mine. After mining ceased, movement
accelerated in the 1980s, 1990s
and 2000s up to a top speed of 20 to
25 cm/a. Since the turn of the century,
the pace of the rock mass movement
slows down. Currently the rate is
slightly below 10 cm/a.
There is a central barrier pillar
between row #4 and row #5. It splits
the subsidence trough of the Southern
flank into a wider Eastern part with
an accumulated maximum of 7-meter
movement of the flank into the
mine, measured horizontally. The
more narrow Western part peaks
at 5.5 meter, the central pillar is
deformed by 3 meter. The inhomogeneous
movement of the Southern
flank into the mine causes steep
gradients in the center of the
structure, consequently strains and
stresses cause cracks and ruptures
(see Figure 5).
The more horizontal overburden
subsidence of the Southern flank
into the stopes causes a vertical
subsidence of the surface topography
(see Figure 6). The surface subsides
by maximal 0.4 meter. The relatively
steep flanks of the surface subsidence
trough indicate the reduced cohe siveness
of the overburden caused
by the tectonic block formation [2]
(see Figure 7).
DECOMMISSIONING AND WASTE MANAGEMENT 59
| Figure 5
Accumulated pillar compression in the Southern flank, measured at different points with extensometer and/or inclinometer [1].
| Figure 6
Rock mass movement of the Southern flank causes surface
subsidence, indicated with blue signature [BGE archive].
| Figure 7
Surface subsidence trough, with cross-sections top East-West, bottom North-South [2].
Decommissioning and Waste Management
Ground Control and the Principle of Minimizing Radiological Exposure as Key Drivers for the Recovery of Radioactive Waste Out of the Asse II Mine ı Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
atw Vol. 66 (2021) | Issue 2 ı March
DECOMMISSIONING AND WASTE MANAGEMENT 60
| Figure 9
Retrieval scheme [1].
| Figure 8
Brine influx shown schematically with brine entering the salt structure at roughly -500 meter, then continuing its flow
downwards to the water intake. Small picture right top shows schematically the damage to the horizontal pillars,
small picture right bottom shows the main intake at -658 meter [2].
Explanation
The stress redistribution during the
mining period of the Southern district
caused the bearing structure of the
mine to creep. The structural integrity
stayed intact. Deformation was
proportional to excavation. The
bearing structure was fully functional
and protected the mine by accepting
the additional stresses and redistributing
them by movement.
After mining suspended, the rock
mass movement continued in the
1970s. The bearing structure increasingly
started to fail by breaking
instead creeping and subsequently
lost load capacity. After accumulating
around 2 meters of compression,
specifically the horizontal pillars
between floor and roof of the stopes
cracked and the movement of the
Southern flank into the stopes
accelerated. Obviously, the design of
the bearing structure was not
sufficient for the extended life time of
many decades for the Asse mine. The
extraction ratio of up to 60 % in
the Southern mining district was too
high for long term stability.
The rock masses of the overburden
are tectonically fragmented at the
Southern flank of the Asse structure.
The coherence of the formally joint
layers of rock is reduced. When the
rock masses get in motion, blocks of
rock can move along slicks and slides.
Continued movement reduces the
shear strength of the overburden
further. The load on the bearing
structure of the mine continues to
rise. Movement accelerates the
resulting compression of the pillars
too. The rock masses of the overburden
deform and finally crack not
only more and more pillars, but also
the salt barrier between the stopes
and the overburden. After 5 meter of
pillar compression the moving rock
masses increasingly hit the backfill
material, which was brought into the
mine in the 1990s. The backfill material
built up counter- pressure against
the incoming Southern flank.
Rock mass movement decelerated
from 2000 onwards until today and
total pillar compression reached up to
7 meters in some places. It will take
possibly another 2 meters movement
over the next decades, until compaction
of the backfill material is
completed and rock mass movement
finally ends.
Brine Influx
When deformation of the Sothern
flank accelerated, the salt barrier
between mine and overburden
cracked. The stopes and the fluid
paths of the overburden connected
hydraulically, starting in the top of the
Eastern trough, close to the barrier
pillar in the center. There the salt
barrier is thin and the deformation
gradient is large.
Brine influx was first noticed in the
1980s and rose to 12.5 m 3 per day up
to now. The main water intake moved
over the years to the Western side of
the central barrier und downwards
by 120 meter. The exact fluid path is
unknown (see Figure 8). Changes in
flow rate and intake location during
the last 30 years happened sudden
and stepwise from one stable level to
the next. It seems that shifting blocks
in the overburden opened new fluid
paths along faults, slicks and slides
and closed existing ones. This caused
sudden changes of the brine influx,
both in rate and location.
The specific weight of the brine
diminished slightly over the last
30 years. This indicates a washing out
of the fluid path, as the solution of
salt by the groundwater when flowing
into the mine obviously decreased.
The Southern flank will continue
to move into the mine. Because of
the variance in pillar dimension, the
movement will not be uniform. The
overburden, the protective salt barrier
within the salt structure and the
pillars are partially cracked. Therefore,
it is possible, that in the next
decades new fluid paths develop and
already existing paths continue to
wash out, the flow rate increases or
the main intake location moves
further down within the mine and
approaches the radioactive waste at
the -750 meter level. These scenarios
may not develop at all, or trends
will be linear. But it is also possible,
that these developments unfold
dynamically.
Decommissioning and Waste Management
Ground Control and the Principle of Minimizing Radiological Exposure as Key Drivers for the Recovery of Radioactive Waste Out of the Asse II Mine ı Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
atw Vol. 66 (2021) | Issue 2 ı March
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DECOMMISSIONING AND WASTE MANAGEMENT 61
Retrieval of the
radioactive Waste
Baseline
In recent years, many repository
concepts for high active waste include
the option for waste retrieval, both
during operations and after closure.
This is an engineered approach,
with specific design considerations
for waste canisters, mine layout and
backfill technology. The vocabulary in
use is retrieval and retrievability for
the readiness to do so.
In contrast to this, the Asse project
recovers waste canisters of unknown
condition out of unstable geotechnical
environment. This paper therefore
uses the term recovery for the process
within the emplacement chamber
and retrieval for the entire process including
the engineered process of
transferring the overpacks from the
emplacement chamber to the waste
treatment and interim storage facility.
Between 1967 and 1978, about
47,000 m 3 of low- and intermediatelevel
radioactive waste was emplaced
in the Asse II mine on behalf of
the German government. For this
purpose, existing stopes on the
511- meter level (medium-level waste)
and on the 725- and 750-meter levels
were used as emplacement chambers.
Due to increasing public criticism of
the pIans for the closure of the mine
under the mining law, the facility was
later placed under nuclear law. Since
the long-term safety required by
nuclear law for the stored waste
cannot be proven with the existing
knowledge and uncertainties about
the hydrogeological situation of the
Asse, it was decided in 2009 to recover
the waste. The legal basis was created
in § 57 b of the Atomic Energy Act.
Recovery and retrieval is a complex
undertaking that will require several
decades to prepare and execute. It
includes all underground and surface
process steps that involve the handling
of radioactive materials, starting
with the activities for recovering the
radioactive waste and ending with
interim storage (see Figure 9). The
basic procedure is described in the
recovery and retrieval plan [1].
The particular challenge of wasterecovery
is to reconcile basically
contradictory requirements in one
concept: On the one hand, the mine
must be stabilized by backfilling and
closure measures in such a way that
occupational safety for underground
workers is ensured, that beyonddesign-basis
brine influx (AüL) is
avoided as far as possible, and that
its potential effects are reduced as
much as possible. On the other hand,
accesses to the waste chambers must
be maintained or established in order
to recover the waste. The excavations
and underground measures required
for this purpose must not have an
unacceptable impact on the stability
and hydrogeological conditions.
Figure 9 shows the main steps of
the retrieval process, starting underground
with the recovering of
the waste from the emplacement
chambers (ELK). Via the retrieval
mine that is being built for this
purpose and the associated new
shaft 5 (see Figure 10), the waste
is transported to the surface in a
special overpack. In the above ground
facilities the waste will be characterized
as well as treated and packaged
(conditioned). Afterwards it is stored
in an interim storage facility.
Figure 10 shows in red the
emplacement chambers within the
existing mine. The future retrieval
mine with its shaft (shaft 5) is situated
to the right of the existing mine. This
new infrastructure is necessary to
Decommissioning and Waste Management
Ground Control and the Principle of Minimizing Radiological Exposure as Key Drivers for the Recovery of Radioactive Waste Out of the Asse II Mine ı Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
atw Vol. 66 (2021) | Issue 2 ı March
DECOMMISSIONING AND WASTE MANAGEMENT 62
| Figure 10
Existing mine and retrieval mine as well as emplacement chambers at -750 m (in red) [2].
| Figure 11
Recovery technology adapted to specific conditions of emplacement chambers [1].
enable an efficient recovery operation
of the waste under the conditions of
nuclear safety requirements.
Design parameters
In addition to the existing geological
and hydrogeological situation, special
challenges for recovery arise from the
condition of the waste containers,
which is not precisely known. It must
be assumed that a considerable part of
the containers is no longer intact, i.e.
at least leaking or destroyed to such
an extent that handling, e.g. by means
of a grab, is no longer possible. In
addition, it can be assumed that the
containers cannot be easily detached
from the surrounding salt crust. While
emplacing containers, they have been
embedded in crushed salt. Furthermore,
the documentation of the waste
does not allow a clear determination
of the radioactive inventory of each
container.
The handling and transport of
radioactive waste underground must
meet the safety requirements for the
operation of a nuclear facility.
Potential incidents during handling
must be controlled. Radiation protection
of personnel must be ensured
at all times, both during normal
operation and in the event of
incidents. Radio active emissions –
especially after opening of the
emplacement chambers – must
comply with the permissible limits for
the personnel below and above
ground and for the general public.
The technology to be used for
recovery must be designed to take into
account the geological and hydrogeological
conditions as well as
| Figure 12
Delimitation of precautionary and emergency measures of emergency planning with naming of exemplary measures [1].
Decommissioning and Waste Management
Ground Control and the Principle of Minimizing Radiological Exposure as Key Drivers for the Recovery of Radioactive Waste Out of the Asse II Mine ı Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
atw Vol. 66 (2021) | Issue 2 ı March
the safety-related and radiological
requirements. In addition, it must be
able to react to the challenges posed
by the waste containers. This includes,
for example, dealing with defective
casks or casks that are firmly trapped
by the salt crust, as well as with the
uncontrolled behavior of casks in
stacks and dumping cones.
The detailed planning of the
re covery technology for the radioactive
waste is carried out on the basis
of the available concept studies,
initially for the waste chambers on
the -511 and -725 meter levels. By
using small- volume excavation technologies,
the structural integrity of
the mine will be affected as little as
possible. For the recovery of waste
from the chambers on the -750-metre
level a comparison of two technological
approaches is currently being
carried out.
Figure 11 shows the status of concept
planning for recovery technology.
Different recovery techniques are
being developed, tested and used
for the respective emplacement conditions.
For the individual chambers
on the 511 m and 725 m levels, the
current plans envisages a grapple
that is guided on the floor or via a
rail system on the roof of the chambers.
For the geotechnically unstable
chamber rows on the -750 m level,
sequential recovery with im mediate
backfilling for stabilization is preferred.
Alternatively, the use of largevolume
shield tunnelling machines is
considered.
Precautionary and
Emergency Measures
According to the provisions of the
Atomic Energy and Mining Law, precautionary
measures against possible
operational incidents and accidents
must be taken as a prere quisite
for recovery. In this context, above
all, the possibilities of a direct attack
by an AüL on the waste chambers
before and during retrieval must
be pre vented or reduced as far as
possible. To achieve this, the BGE
pursues a concept of emergency
planning that provides for so-called
precautionary and emergency
measures (see Figure 12).
The most important measure is the
backfilling of the remaining void
volumes and the construction of
hydraulic barriers around the waste.
However, even after the backfilling
measures have been completed, a void
volume of almost 1 million m 3 will
remain, mostly as pore space in the
backfill.
It is also important to seal the
stopes and cracked pillars below the
current main intake location on the
-638 meter level in order to block any
internal flow path that may develop
within the excavation field. For this
purpose, an injection screen is to be
installed underneath the collection
point in the next few years.
Constructing a new retrieval mine
outside the existing mine building
also contributes to the precautionary
measures. In this way further
weakening of the central part of the
geotechnically stressed mine infrastructure
and a further loss of integrity
is avoided.
Outlook
The hydrogeological conditions will
be clarified by extensive exploration
measures. In particular, the exact
location of the border between salt
structure and overburden as well as
the possible flow paths at layer
boundaries, in aquifers and along
fault paths must be clarified. A central
element of the safety assessment for
the retrieval will be the proof that no
additional hydrogeological risks will
arise from the further interventions in
the salt structure associated with the
project. To this end, a large number of
core drillings will be made from below
and above ground. An elaborate
three-dimensional reflection seismic
survey was carried out in the winter
of 2019/2020. Only with precise
knowledge of the critical hydrogeological
features can the new
retrieval mine be developed in such a
way that it avoids possible hydrogeological
hazards, such as approaching
the salt envelope or other potential
flow paths.
Bibliography
[1] Plan zur Rückholung der radioaktiven Abfälle aus
der Schachtanlage Asse II-Rückholplan; BGE 2020
[2] Schachtanlage Asse II: Gebirgsbeobachtungsgespräch,
BGE 2020, YouTube
[3] Dr.-Ing. Oleksandr Dyogtyev: Numerische Analyse des
Tragverhaltens komplexer gebirgsmechanischer untertägiger
Systeme mit filigranen Strukturen bei Anwesenheit von
Imponderabilien; Dissertation, TU Clausthal, 2017
Authors
Beate.Kallenbach-Herbert@bge.de
Beate
Kallenbach-Herbert
Managing Director
Bundesgesellschaft für
Endlagerung (BGE) mbH
Peine, Germany
Beate Kallenbach-Herbert is a graduate mechanical
engineer. Until the end of 2018, she was head of the
Nuclear Technology and Plant Safety Division at the
Öko-Institut in Darmstadt. There she focused on the
disposal of radioactive waste, the design of processes,
and management structures, taking into account the
participation of stakeholders and the public, safety
management and culture, and environmental impact
assessments. Beate Kallenbach-Herbert was also a
member of the Waste Management Commission (ESK)
and the Swiss Deep Geological Repositories Expert
Group (ESchT) of the Federal Environment Ministry.
As a member of the Management Board, Beate
Kallenbach-Herbert is responsible for the commercial
divisions of the BGE.
Foto: ©Anke Jacob, BGE
Dr. Thomas Lautsch
Managing Director
Bundesgesellschaft für
Endlagerung (BGE) mbH
Peine, Germany
Thomas.Lautsch@bge.de
Dr. Thomas Lautsch is a graduate mining engineer.
Before becoming Managing Director of DBE, a
predecessor organisation of BGE, he held various
positions in management boards of both national and
international mining companies. His responsibility
included technology, production and legal compliance
of major mining operations and large scale project
development in the coal and copper industry,
predominantly in the deep underground. Currently
Thomas Lautsch is responsible for the Asse, Konrad,
Morsleben and Gorleben mines, which are all
repository projects at different stages of their life cycle
from planning to construction to closure. He is also
responsible for technology development within BGE.
Foto: ©Anke Jacob, BGE
Sebastian Voigt
Project engineer,
directly reporting to the
Managing Director
Bundesgesellschaft für
Endlagerung (BGE) mbH
Peine, Germany
Sebastian.Voigt@bge.de
Sebastian Voigt is a graduate Mining Engineer. Until
2018 he had a leading role in German pottash mines
and related projects and worked as a Project Engineer
for BGE in 2019. Since 2020 he is a Consultant of the
Technical Management.
DECOMMISSIONING AND WASTE MANAGEMENT 63
Decommissioning and Waste Management
Ground Control and the Principle of Minimizing Radiological Exposure as Key Drivers for the Recovery of Radioactive Waste Out of the Asse II Mine ı Thomas Lautsch, Beate Kallenbach-Herbert and Sebastian Voigt
atw Vol. 66 (2021) | Issue 2 ı March
AT EDITORIAL A GLANCE
64
Deep Isolation
Future of Nuclear Industry
Brighter if Nuclear Waste Issue Can Be Solved
Governments worldwide are considering alternatives to fossil fuel energy
sources and taking a fresh look at nuclear energy. Even while some
countries, including Germany, Belgium and Spain, are contemplating the
permanent shutdown of their existing nuclear fleets, others such as the
United Kingdom, France, Finland, Estonia and the Netherlands are exploring
advanced reactors.
Yet the primary route for deep geologic disposal has
been via mined repositories — an expensive and often
unpopular option.
Founded in 2016 in Berkeley, Calif., by environmentalist
Elizabeth Muller and University of California, Berkeley,
physicist Richard Muller, Deep Isolation uses an innovative
approach to deep geologic disposal. The founders
believe that we have a responsibility to find a disposal
solution that can be implemented in reasonable timeframes,
rather than passing on the problem to future
generations.
Cost can be a significant barrier to new nuclear power,
but in the minds of many there is an even bigger
concern: the lack of a nuclear waste disposal solution.
The public is demanding a safe and equitable solution
to the disposal of spent nuclear fuel, and is increasingly
wary of “temporary” solutions when there is no plan in
place for permanent disposal.
The good news is that innovation in nuclear waste
disposal has opened up new disposal options. Meet
Deep Isolation, an emerging nuclear waste disposal
company aiming to break through the nuclear waste
disposal stalemate.
Deep Isolation Offers New Path
Forward for Nuclear Waste
Since the first nuclear power plant was opened in the
Soviet city of Obnisk in 1954, more than 500 nuclear
power plants have followed, contributing more than
10 percent of the world’s electrical power. While nuclear
power plants are considered low-carbon, they create
radioactive waste that can remain hazardous to the
environment and human health for tens of thousands
of years.
For decades, it has been universally accepted across continents,
governments, regulators, academics, scientists
and the nuclear industry that the preferred solution for
the long-term disposal of high-level nuclear waste
(HLW) is through deep geological disposal.
With core values of environmental stewardship,
scientific ingenuity, and social license, Deep Isolation
believes early community engagement can help alleviate
some of the obstacles previous nuclear waste disposal
efforts have faced.
“Communities know what is best for them, and we are
here to support that process,” said CEO Elizabeth Muller.
She added, “By working together we can improve the
quality of the solutions we are considering. Everyone
needs a seat at the table and a reasonable expectation
that their input will be incorporated.”
Deep Isolation is leveraging existing drilling technologies
to put waste into boreholes deep underground.
This method means no humans are working underground,
making it safer and less expensive.
While vertical boreholes were previously considered
for nuclear waste in the United States, Deep Isolation’s
design takes advantage of innovations in directional
drilling to enable additional cost and safety benefits.
The Deep Isolation design builds upon the vertical
option, by adding a gradual curve at the terminus of
the vertical path and extending in a horizontal direction.
This design allows the waste corrosion-resistant
canisters to be emplaced under rock that has been
isolated from the biosphere for a million years or more.
This method means there’s no direct path for the movement
of radionuclides to the surface. Independently
peer reviewed safety calculations published by Deep
Isolation in March of 2020 examined 400 modeled
scenarios and concluded that the risk of radiation
exposure to humans is significantly lower than the U.S.
standard.
At a Glance
Deep Isolation
atw Vol. 66 (2021) | Issue 2 ı March
The waste can then be retrieved during a set time
period, if needed, or left permanently with the borehole
safely sealed.
One advantage of an on-site borehole repository is that
it eliminates the need to transport waste from the
reactor site to a centralized mined repository. While
transportation has proven very safe, there can be
considerable concern from communities located along
transportation paths, and this has delayed previous
efforts that rely on long-haul transportation.
Solving a problem that has existed for decades in the
nuclear industry has had its challenges as some have
expressed skepticism about new disposal methods.
But on Jan. 16, 2019, Deep Isolation did something
many thought was impossible: It became the first
private company to successfully demonstrate to an
invited cross-section of community, industry, government
officials, and investors the emplacement and
retrieval of a prototype nuclear waste canister in a test
borehole about half a mile underground.
The success of this demonstration in Cameron, Texas,
helped lead to important collaborations with industry
leaders, including Bechtel and NAC International, which
is working with Deep Isolation to design its waste
disposal canisters, and Schlumberger, a leader worldwide
in the oilfield industry that provided the test facility.
Deep Isolation recently opened a London-based office
to better serve countries in Europe and Asia and began
work on its first contracts to assess the feasibility of its
solution in specific locations and for specific waste
inventories.
A recent study published by the Electric Power Research
Institute (EPRI) indicates that locating a deep borehole
repository at the site of a hypothetical advanced reactor
in the southeastern United States could be both safe and
cost-effective.
Estonia Project Sets Example for
Advanced Nuclear in European Union
On Feb. 1 Deep Isolation and advanced reactor developer
Fermi Energia announced the results of a deep
borehole geology study — the first such study between
a European company and Deep Isolation.
While countries such as Finland, Sweden and France are
building mined repositories for nuclear waste, a deep
horizontal borehole solution in Estonia would locate
the waste much deeper, would cost considerably less
than a mined repository and could be deployed in a
shorter timeframe.
A cost analysis by Deep Isolation showed the planned
expenditure on mined geological disposal in the
U.S., Canada, Sweden and the U.K. alone amounts to
$172 billion in 2020 prices — not including the costs of
interim storage.
While many advanced reactor companies have yet to
explain how they plan to dispose of their spent nuclear
fuel, Fermie Energia, which aims to bring the first small
modular reactor (SMR) to the European Union by the
2030s, took the proactive step of partnering with Deep
Isolation on a qualitative geological readiness assessment
of Estonia’s crystalline basement rock.
The study evaluates geological conditions and potential
risk factors for each of Estonia’s 15 counties, screening
their potential suitability for hosting a deep borehole
repository. Such a repository would isolate radioactive
elements from the Earth’s surface for 1.3 million years.
At that point, any elements that might reach the surface
would be three orders of magnitude below the levels
deemed safe and allowable by international safety
standards.
“As Estonia considers the role that advanced nuclear
power generation can play in delivering a low-carbon
future for the country, citizens and policymakers can feel
confident there is a safe and affordable way to dispose
of the resulting spent nuclear fuel,” said Chris Parker,
Managing Director, Deep Isolation EMEA Limited.
Company Seeking
to be Part of the Solution
Deep Isolation’s success in demonstrating its technology
and engaging in recent studies with governments and
nuclear energy companies such as Fermi Energia illustrate
the types of opportunities for the nuclear industry
to solve the massive problem of nuclear waste disposal.
The company’s 2021 goals include securing additional
contracts with governments and the nuclear industry to
study whether its disposal solution meets their needs.
To further help interested parties and organizations
worldwide better understand how this solution could
work for them, the company hopes to embark upon
further drillhole demonstration
projects so its nuclear waste
solution can be ready to support
the fight against climate Contact
change via the next generation
of nuclear reactors.
www.deepisolation.com
@company/deep-isolation
@DeepIsolation
@DeepIsolation
@deep.isolation
AT EDITORIAL A GLANCE
65
At a Glance
Deep Isolation
atw Vol. 66 (2021) | Issue 2 ı March
66
RESEARCH AND INNOVATION
Assessment of Loss of Shutdown
Cooling System Accident during
Mid-Loop Operation in LSTF Experiment
using SPACE Code
Minhee Kim, Junkyu Song, Kyungho Nam
1 Introduction During a plant outage, while the fuel remains in the core, the core is cooled by Residual Heat
Removal (RHR) system. The loss of RHR can lead to loss of heat removal from the core and is a safety concern. During
certain stage of maintenance, such as installation of steam generator nozzle dams, the RCS coolant level is lower to
centerline of hot leg and cold leg pipes. This is called mid-loop operation and the coolant level is lowest while the fuel
remains in the core. Therefore, the loss of RHR during mid-loop operation represents the most limiting condition for
loss of RHR incidents. The accident can be occurred by an isolation valve closure or a loss of vital ac power in the RHR
suction line, or a loss of RHR pump flow due to air ingestion. If the loss of RHR flow should continue for a certain period
of time, the reactor vessel coolant has possibility on core boiling and uncover.
In order to analyze the thermal
hydraulic phenomena following the
loss of RHR accident, the numerical
and experimental studies have been
performed. Nakamura et al. con ducted
the experiments of loss of RHR
accident during mid-loop operation in
the ROSA-IV/LSTF facility [1]. In the
experiments, the primary pressurization
behavior after the coolant boiling
in the core was observed. Also, the
system integral responses were investigated
through analyzing the steam
and noncondensable gas behavior in
the RCS. The opening location and
size in a pressurizer or a horizontal leg
was analyzed as major experimental
parameters.
In numerical approach, the major
thermal hydraulic phenomena and
process were evaluated using RELAP5
system code [1, 2]. The calculation
results were compared with ROSA-IV/
LSTF experimental data.
The present paper is focused on the
assessment of SPACE 3.0 in predicting
the system primary and secondary
behavior following the loss-of-RHR
accident during the mid-loop operation
of LSTF experiment in reference
to NUREG/IA-0143 report [2]. The
calculated results are compared with
RELAP5 results and experimental
data in terms of steady-state and
transient behavior.
2 Code Descriptions
The SPACE code, which is Safety
and Performance Analysis Code for
Nuclear Power Plants, has been
developed in recent years by the Korea
Hydro & Nuclear Power Co. through
collaborative works with other Korean
nuclear industries and research
institutes, and is approved by Korea
Institute of Nuclear Safety (KINS)
in March 2017. The SPACE is a
best- estimate two-phase three-field
thermal- hydraulic analysis code in
order to analyze the performance and
evaluate the safety of pressurized
water reactors. Each field equation is
discretized based on finite volume
approach on a structured mesh and an
unstructured mesh together with an
one-dimensional pipe meshes [7]. For
time integration method, the semiimplicit
scheme is used. The SPACE
code is package of input and output,
hydrodynamic model, heat structure
model, and reactor kinetics model.
The input package performs a
reading the input and restart files, a
parsing the data files, an allocating
the memory, and checking the unit
conversion. Hydrodynamic model
package is composed of constitutive
models, special process models, and
component models, and hydraulic
solver. The hydraulic solver is based
on two-fluid, three-field governing
equations, which are composed of gas,
continuous liquid, and droplet fields.
Therefore, SPACE code have the
advantage in solving a dispersed
liquid field as well as vapor and
continuous liquid fields in comparison
with existing nuclear reactor system
analysis codes, such as RELAP5 (ISL,
2001), TRACE (NRC, 2000),
CATHARE (Robert et al., 2003), and
MARS-KS (KAERI, 2006). Constitutive
models are composed of correlations
by the flow regime map to
simulate the mass, momentum, and
energy distributions, such as surface
area and surface heat transfer, surface-wall
friction, droplet separation
and adhesion, and wall-fluid heat
transfer. In order to analyzed the
physical phenomena of the NPP,
special process and system components
are modeled. Major special
process and component models are
critical flow model, counter current
flow limit model, off-take model,
abrupt area change model, 2-phase
level tracking model, pump model,
safety injection tank model, valve
model, pressurizer model, and
separator model, etc.
The package of heat structure
model calculates the heat addition
transfer and removal. The heat
structure model includes transient
heat conduction of rectangular or
cylindrical geometry, and has various
boundary conditions of convection,
radiation, user defined variables such
as temperature, heat flux, and heat
transfer coefficient.
In order to calculate the nuclear
fission heat of a fuel rod, the point
kinetics methodology is used in the
heat conduction equation. Reactivity
feedbacks are considered in terms
of moderator temperature, boron
concentration fuel moderator density,
reactor scram, and power defect.
Decay heat of ANS-73, -79, and -2005
models are also implemented.
The 3.0 version of the code was
released through various validation
and verification using the separated or
integral loop test data and the plant
operating data. The approved code
version will be used in the safety
analysis of operating PWR and the
design of an advanced reactor.
3 Modeling Information
Figure 1 shows the nodalization to
simulate the LSTF facility with the
SPACE code. The modeling is based on
179 hydrodynamic cell and 202 heat
Research and Innovation
Assessment of Loss of Shutdown Cooling System Accident during Mid-Loop Operation in LSTF Experiment using SPACE Code ı Minhee Kim, Junkyu Song, Kyungho Nam
atw Vol. 66 (2021) | Issue 2 ı March
RESEARCH AND INNOVATION 67
| Figure 1
Nodalization diagram for LSTF experiment.
structures. The reactor pressure vessel
includes the lower plenum, upper
plenum, downcomer, and core, upper
head and guide thimble channel (cell
100 to 156). The core is modeled as
two channel with 12 cells per each
channel connected by crossflow. The
two channel arrangement is adopted
in order to assess the multi-dimensional
effect such as the natural circulation
behavior in the core. The power
distribution of the two channel core
is 60 % for high power channel and
40 % for low power channel.
The LSTF system are described by
an intact-loop (cell 400 to 499) and a
broken-loop (cell 200 to 299) in an
almost symmetrical way. Each loop
consists of a SG inlet and outlet, loop
seal, SG U-tube, reactor coolant pump,
hot leg, and cold leg. The pressurizer
is connected to the hot leg of intactloop
through the surge line elements.
The secondary sides of two SGs (cell
300 to 399 and 500 to 599) are composed
using an identical nodalization.
In order to analyze the cold leg
opening with loss of RHR accident,
the openings are modeled by a trip
valve. The opening sizes are equivalent
to 5 % of cold leg cross area, and
the opening are located at centerline
of the cold legs. The steady-state
results are established for conducting
a null transient calculation.
4 Results and Discussions
4.1 Initial conditions
In order to confirm the modeling
methodology and input condition,
the steady-state calculation result is
compared with experimental data.
The major parameters in steady-state
condition are summarized in Table 1.
The core power was 430 kW with
decay heat at about 20 hours after the
reactor shut down. The water levels of
hot and cold legs maintain at the
middle of the loop. Core power and
loop temperature were set to target
values for calculation. Initial conditions
of loop water level represent
the same value with target data. The
pressurizer and SGs relief valves were
opened to maintain an atmospheric
pressure. Overall results show that
SPACE code have a reasonable agreement
with target values in steady state
analysis. The steady-state results
are established for conducting a null
transient calculation.
4.2 Transition behavior
The transient calculation was initiated
by decreasing the RHR pump flow rate
from the initial value to zero during
20 seconds with opening the cold
leg valve. The pressurizer and SGs
relief valves were closed with cold
leg opening.
Parameters LSTF SPACE
Core power (kW) 430 430.0
Hot-leg temp.(K) 334 334.1
Cold-leg temp.(K) 318 318.0
Primary pressure (MPa) 0.1013 0.1013
Water level at loops (m)
p hot leg void
p cold leg void
| Table 1
Steady state calculation results.
Mid-loop
Mid-loop
p 0.55
p 0.47
Secondary pressure (MPa) 0.1013 0.1013
Secondary fluid temp. (K) 317 317.0
Water level in SG (m) 10 10.2
| Figure 2
Pressure distribution at hot-leg and cold-leg in intact loop.
Research and Innovation
Assessment of Loss of Shutdown Cooling System Accident during Mid-Loop Operation in LSTF Experiment using SPACE Code ı Minhee Kim, Junkyu Song, Kyungho Nam
atw Vol. 66 (2021) | Issue 2 ı March
RESEARCH AND INNOVATION 68
| Figure 3
Calculated flow rate between guide tube and upper head.
| Figure 4
Differential pressure at crossover leg in broken loop.
| Figure 5
Differential pressure at crossover leg in intact loop.
| Figure 6
Differential pressure at reactor core.
| Figure 7
Liquid temperature in core.
| Figure 8
Fluid temperature at hot and cold leg in intact loop.
| Figure 9
Fluid temperature at steam generator secondary side.
| Figure 10
Collapsed water level in reactor pressure vessel.
Research and Innovation
Assessment of Loss of Shutdown Cooling System Accident during Mid-Loop Operation in LSTF Experiment using SPACE Code ı Minhee Kim, Junkyu Song, Kyungho Nam
atw Vol. 66 (2021) | Issue 2 ı March
| Figure 11
Void fraction in core upper plenum.
Figure 2 shows the pressure
phenomena of hot and cold legs in
intact loop after the loss of RHR
accident. At about 1,500 seconds, the
core liquid started to boil and the
steam migrated toward the hot legs
from the core through core upper
plenum. Thus, the pressure in
the hot leg started increasing
rapidly at about 1,600 seconds. At
about 2,100 seconds, the pressurization
rate reduced immediately.
The steam flow of guide tubes
express the cause and effect of pressure
behavior at this time as shown in
Figure 3. The guide tubes were initially
submerged under water in upper
plenum. As the water level decreased
below the guide tube bottom opening
due to the boil off, the steam started to
be discharged into upper head with
large volume. The SPACE 3.0 code
showed that the pressurization rate
was higher than the RELAP5/MOD3.2
results. The high pressurization rate
resulted in the accurate simulation of
Loop Seal Clearing (LSC) comparing
with experiment.
Figures 4 and 5 show the differential
pressure behavior of downflow
and upflow sides in the crossover legs.
When the Loop-Seal Clearing(LSC)
occurred, the crossover leg of broken
loop was immediately emptied. The
calculation well predicted the overall
LSC behavior. Figure 4 also shows
that the condensate liquid from the
SG U-tube wall started to accumulate
in upper flow direction from about
6,400 seconds. Such a liquid accumulation
of the crossover leg resulted
in preventing the gas flow from the
hot leg to the cold leg. Because of
limited steam condensation of SG
U-tube wall, the pressure is re-increasing
gradually in the hot leg as shown
in Figure 2.
In the intact loop, the differential
pressure after the LSC was predicted a
little higher than that before the LSC.
| Figure 12
Void fraction in broken loop.
The partial LSC means that the inflow
from the core to the cold leg was lower
than in the experiment. Because of this
small amount of the inflow, the coolant
inventory of the core is underestimating.
Figure 6 represents that the
differential pressure behavior in the
core was underestimated after the LSC.
Figure 7 represents liquid temperatures
behavior at the reactor
core. The experimental data are fluid
temperatures at midsection of the
core. The core coolant became
stagnated and the liquid temperature
behavior immediately increased. After
the liquid temperature reached
saturation value, the coolant started
to boil off and the temperature
remained constant over time. The
calculation results agreed well with
the experiment data.
Figure 8 shows liquid temperatures
in hot and cold legs in broken
loop. After the saturation of steam
in core upper plenum, the liquid
temperature in the hot leg increased
to the steam temperature in the
experiment. Because the experimental
data was measured at the ceiling of
the horizontal pipe, the temperature
was a steam temperature after the
hot leg and cold leg were sufficiently
voided. This results in the difference
with calculated liquid temperature
after the LSC.
Figure 9 shows liquid temperature
in the bottom sides of the SG U-tubes.
Because the SPACE code can
well simulate the steam migration
phenomena into SG U-tubes, the
temperature behavior was similar
with experiment than RELAP code.
Figure 10 shows the collapsed
water level of reactor vessel. Because
the water level decreased, the hot legs
and core upper plenum reach to the
mid-water level in the early phase, as
shown in Figures 11 and 12. When
the LSC phenomena occurred, the
cold legs became completely voided.
The collapsed water level of the
reactor vessel increased immediately
following the water inflow from the
crossover and cold legs.
5 Conclusion
The SPACE 3.0 code was assessed for
the loss of RHR accident during the
mid-loop operation in ROSA-IV/LSTF
experiment. The major thermal
hydraulic phenomena was compared
with experimental data and RELAP
code results.
Based on the results and comparison,
it is observed that SPACE
code shows good agreement with
experimental data or overall parameters,
and it is observed that SPACE
code can effectively simulate during
the transient.
References
[1] H. Nakamura, J. Katayama and Y. Kukita, “RELAP5 Code
Analysis of a ROSAIV/ LSTF Experiment Simulating a Loss
of Residual Heat Removal Event during PWR Mid-Loop
Operation,” Proceeding of the 5th International Topical
Meeting on Nuclear Reactor Thermal Hydraulics (NURETH-5),
Vol. V, pp. 1333-1340 (1992)
[2] K. W Seul, Y. S. Bang, S. Lee, and H. J. Kim, “Assessment of
RELAP5/MOD3.2With the LSTF Experiment Simulating a Loss
of Residual Heat Removal Event During Mid-Loop Operation”,
NUREG/IA-0143 (1998)
[3] S. J. Ha et al., “Development of the SPACE Code for Nuclear
Power Plants,” Nuclear Engineering & Technology, Vol. 43,
No. 1, pp. 45 (2011)
Author
Minhee Kim
Central Research
Institute, Korea Hydro &
Nuclear Power Co.,
Daejeon, Korea
minhee.kim@khnp.co.kr
Minhee Kim studied Mechanical engineering and
completed her Ph.D. in 2014 at the Seoul National
University. The topic of her thesis was ‘Computational
study on active flow control using synthetic jet for
threedimensional aircraft configuration’. Minhee Kim
is working as a Senior Research Engineer at KHNP.
RESEARCH AND INNOVATION 69
Research and Innovation
Assessment of Loss of Shutdown Cooling System Accident during Mid-Loop Operation in LSTF Experiment using SPACE Code ı Minhee Kim, Junkyu Song, Kyungho Nam
atw Vol. 66 (2021) | Issue 2 ı March
70
NEWS
Top
World Cancer Day:
COVID-19’s Impact on the
Fight Against Cancer
(iaea) Inequality is present in most
aspects of life, but in the global fight
against cancer the stark difference
between industrialised countries and
developing nations in their ability to
diagnose and treat the disease, is a
matter of life and death. Most new
cancer cases today occur in lowand
middle-income countries, and
COVID- 19 has further strained the
capacities of health infrastructure.
Strengthening these health systems is
key in the global fights against both
cancer and COVID-19.
Marking this year’s World Cancer
Day on 4 February, the IAEA held a
panel discussion, exploring the impact
the COVID-19 pandemic has had on
cancer care globally and the support
provided by the IAEA to radiotherapy
practitioners worldwide. Panelists
called for more and urgent action to
address the wide gap in diagnosis and
therapy access between developed and
developing countries.
“This event is an opportunity to be
reminded of where we are in our
continuous efforts; we can’t stop for a
single minute in fighting cancer,” said
IAEA Director General Rafael Mariano
Grossi in his opening remarks. Speaking
from IAEA Headquarters in Vienna
to a global audience online, Grossi
explained that COVID-19 stretched national
medical services, disrupted supply
chains and put up numerous other
barriers to cancer patients seeking the
urgent care they needed. He highlighted
that a recent IAEA survey found
that in March-April 2020, diagnostic
procedures fell on average by more
than half in the 72 countries surveyed.
The IAEA supports national governments
in using nuclear science and
technology to better diagnose, treat
and manage cancer. It also helps countries
in procuring equipment, training
medical professionals and secure
resources from donors. The pandemic
has not stopped the IAEA in providing
support in these areas.
Voices for action
Cancer is the second leading cause of
death worldwide, responsible for onein-six
fatalities in 2018 and taking the
lives of 9.5 million people. COVID-19,
a highly transmissible virus, has to
date infected over 103 million people
globally, and killed 2.24 million. Tackling
cancer in the shadow of COVID-19
has been a priority for the IAEA, which
has been cooperating with the World
Health Organization to provide assistance
around the world.
Speaking first in the day’s panel discussion,
May Abdel-Wahab, Director
of the IAEA’s Division of Human
Health highlighted the importance of
radiation medicine in the modern
management of cancer patients and
shared how the IAEA is promoting
and developing radiation medicine
in Member States in light of the
COVID- 19 pandemic.
“Radiotherapy has been an optimal
treatment option during the
COVID-19 pandemic for cancer
patients because it does not compete
for in-demand hospital resources such
as intensive care unit beds and is
amenable to treatments with shorter
regimens of radiation, thus minimizing
exposure to patients and medical
personnel,” she said. “The IAEA has
supported medical professionals
working in radiation oncology,
nuclear medicine and radiology
practices through guidance documents,
webinars and publications to
ensure the continuity of these essential
services.”
While in the last 5 years, there has
been an increase of around 5 per cent
in the number of radiotherapy centres
globally, still more than 70 countries
have no radiotherapy machines at
all – 28 of them are in Africa.
Lisa Stevens, Director of the IAEA’s
Programme of Action for Cancer
Therapy (PACT), shared how the
Agency is supporting countries in cancer
control and resource mobilisation
for cancer activities under the current
circumstances. “In spite of the pandemic,
we were able to support three
Member States in reviews of their cancer
control activities and thirteen
Member States held meetings with international
experts to review progress
and ongoing needs identified in previous
imPACT Reviews. We also were
able to continue to mobilize financial
resources to support cancer activities.”
| www.iaea.org (203500758)
World
Canadian and European
nuclear industries partner
to promote clean energy and
new nuclear
(foratom) The Canadian Nuclear
Association (CNA) and the European
Atomic Forum (FORATOM) have
signed a Memorandum of Understanding
(MoU) to collaborate in nuclear
and promote clean, inno vative and
advanced nuclear technologies.
This agreement will strengthen
both associations’ efforts in advancing
nuclear energy’s development,
application, and deployment to meet
climate change goals.
“We are excited to sign this
Memorandum of Understanding with
FORATOM,” said CNA President and
CEO John Gorman. “Nuclear energy
already makes important contributions
to combating climate change.
This agreement will work to ensuring
that nuclear is part of the clean energy
mix to meet the climate change challenge
on both sides of the Atlantic”
“Climate change is a global
challenge” adds Yves Desbazeille,
Director General of FORATOM. “This
is why it is important that all regions of
the world work together to find solutions.
Together, we will be able to send
a coordinated message to our policymakers
with the goal of demonstrating
the important role which different
nuclear technologies can play”.
Massimo Garribba, Deputy Director-
General DG Energy in the European
Commission says: “We welcome the
Memorandum of Understanding
signed between FORATOM and the
CNA. This confirms their willingness to
foster industry to industry collaboration
on the safe use of nuclear energy,
in particular in the context of decarbonisation
priorities – an issue which
the EU is very much committed to”
“We need nuclear to reach net-zero
by 2050,” says the Honourable Seamus
O’Regan Jr., Canada’s Minister of
Natural Resources. “We are working
with our international counterparts to
safely expand nuclear technologies,
such as SMRs, and meet our climate
change goals.”
Canadian-European nuclear cooperation
goes back decades. Canadian
CANDU reactors have been in service
in Romania for nearly 30 years. At the
same time, European companies have
provided components to the Canadian
nuclear sector and are recognised
internationally for the technology
know-how. The development of new
and innovative nuclear technologies,
such as SMR’s, is expected to further
enhance cooperation between Europe
and Canada.
The MOU addresses the need for
greater dialogue and exploration of
nuclear’ s role in effective environmental
stewardship. It includes:
p advocating for more explicit and
prominent inclusion of nuclear
energy in Europe and Canada’s
energy and environmental policies,
News
atw Vol. 66 (2021) | Issue 2 ı March
Operating Results November 2020
Plant name Country Nominal
capacity
Type
gross
[MW]
net
[MW]
Operating
time
generator
[h]
Energy generated, gross
[MWh]
Month Year Since
commissioning
Time availability
[%]
Energy availability
[%] *) Energy utilisation
[%] *)
Month Year Month Year Month Year
71
OL1 Olkiluoto BWR FI 910 880 720 666 302 6 880 434 276 345 904 100.00 95.10 100.00 93.17 100.59 93.02
OL2 Olkiluoto BWR FI 910 880 720 657 480 7 072 280 266 436 366 100.00 96.67 99.79 96.23 99.26 95.61
KCB Borssele PWR NL 512 484 634 319 129 3 709 851 171 691 285 87.21 91.55 87.18 90.93 86.57 90.15
KKB 1 Beznau 7) PWR CH 380 365 720 276 899 2 726 079 133 034 899 100.00 89.54 100.00 89.39 101.25 89.14
KKB 2 Beznau 7) PWR CH 380 365 720 275 023 2 906 692 140 203 475 100.00 96.01 100.00 95.81 100.57 95.10
KKG Gösgen 7) PWR CH 1060 1010 720 756 222 7 987 722 330 103 957 100.00 94.74 99.97 94.32 99.09 93.73
CNT-I Trillo PWR ES 1066 1003 720 761 458 7 489 180 263 237 206 100.00 90.02 100.00 89.51 98.66 86.72
Dukovany B1 PWR CZ 500 473 300 147 786 3 760 255 119 644 439 41.67 94.78 41.22 94.69 41.05 93.54
Dukovany B2 PWR CZ 500 473 127 63 644 3 207 378 114 250 696 17.64 81.73 17.61 81.49 17.68 79.79
Dukovany B3 PWR CZ 500 473 720 350 844 2 743 756 112 995 492 100.00 71.02 99.51 69.97 97.46 68.25
Dukovany B4 PWR CZ 500 473 720 358 022 3 488 835 114 195 792 100.00 87.51 100.00 87.47 99.45 86.79
Temelin B1 PWR CZ 1080 1030 720 782 490 6 846 642 128 761 455 100.00 79.04 100.00 78.28 100.63 78.72
Temelin B2 PWR CZ 1080 1030 720 792 028 7 286 583 124 769 201 100.00 82.76 100.00 82.54 101.29 83.73
Doel 1 PWR BE 454 433 720 340 489 1 923 493 139 659 553 100.00 52.27 100.00 51.72 101.44 51.26
Doel 2 PWR BE 454 433 720 339 390 1 923 705 138 259 175 100.00 52.98 99.97 52.68 100.76 51.71
Doel 3 PWR BE 1056 1006 720 773 176 7 296 793 270 408 444 100.00 86.46 100.00 86.04 101.14 85.46
Doel 4 PWR BE 1084 1033 603 648 460 6 906 443 276 544 718 83.72 79.63 82.05 78.81 81.78 77.90
Tihange 1 2) PWR BE 1009 962 0 0 0 307 547 424 0 0 0 0 0 0
Tihange 2 2) PWR BE 1055 1008 282 284 090 7 649 298 265 703 817 39.14 92.02 37.73 91.64 37.72 90.99
Tihange 3 PWR BE 1089 1038 720 780 140 5 284 349 285 846 925 100.00 61.47 99.94 60.76 100.11 60.69
NEWS
Plant name
Type
Nominal
capacity
gross
[MW]
net
[MW]
Operating
time
generator
[h]
Energy generated, gross
[MWh]
Time availability
[%]
Energy availability
[%] *) Energy utilisation
[%] *)
Month Year Since Month Year Month Year Month Year
commissioning
KBR Brokdorf DWR 1480 1410 720 1 010 177 9 559 288 370 280 310 100.00 89.86 100.00 85.12 94.69 80.11
KKE Emsland DWR 1406 1335 720 1 014 541 10 367 673 367 967 874 100.00 93.26 99.98 93.18 100.37 91.73
KWG Grohnde DWR 1430 1360 720 950 594 9 457 730 397 732 576 100.00 94.20 99.91 93.96 91.66 81.73
KRB C Gundremmingen 1,2) SWR 1344 1288 29 22 203 8 177 262 349 500 815 4.03 77.51 2.29 75.93 2.27 75.11
KKI-2 Isar DWR 1485 1410 720 1 058 301 10 569 951 376 332 420 100.00 92.53 100.00 92.34 98.71 88.14
GKN-II Neckarwestheim DWR 1400 1310 720 1 003 400 10 075 300 350 313 544 100.00 92.00 100.00 91.93 99.79 89.65
including sustainable finance
(taxonomy);
p support for innovation in nuclear
energy, specifically the development
and deployment of small
modular reactors and advanced
reactors;
p identify and implement initiatives
where FORATOM and CNA could
work together to promote nuclear as
a clean energy source to meet
climate change goals, reduce emissions
and improve the quality of life.
Canada is home to 19 nuclear power
reactors, which produce clean, reliable
electricity, representing 15 per
cent of the country’s total electricity.
Every year in Canada, nuclear energy
avoids 80 million tonnes of CO 2 emissions
by displacing fossil fuels; supports
76,000 direct and indirect jobs;
and contributes $17 billion in gross
domestic product.
Nuclear power generates around
26 per cent of the European Union’s
electricity in 13 countries with 107
reactors (which go up to 141 if we
include all FORATOM members non-
EU Switzerland, UK and Ukraine) that
provide 50% of low carbon electricity.
The industry supports over one
million jobs (direct, indirect and
induced) across the continent with a
turnover of €100 billion a year.
| Full MOU: https://t1p.de/cft8
www.cna.ca
www.foratom.org (21471424)
Technology
3D-Printing is reshaping what’s
possible with nuclear energy
(nei) Leaders, policy experts,
researchers – and now the Biden
administration – know that tackling
climate change will require energy
innovation. Sometimes that means
inventing new technologies in wind,
solar and the next generation of
nuclear reactors, but it can also mean
taking advanced technologies from
other fields and applying them to the
energy sector.
3D-printing is one innovation that
is beginning to revolutionize how
we think about carbon-free energy,
especially nuclear.
What Is 3D-Printing?
3D-printing, or more formally, additive
manufacturing, takes a digital design
and converts it into an actual 3D object,
fashioned from plastic, metal or a
composite. The technology has become
more popular recently and moved from
labs and issues of “Popular Mechanics”
to inside our own homes. Even dentists
*) Net-based values
(Czech and Swiss nuclear
power plants
gross-based)
1) Refueling
2) Inspection
3) Repair
4) Stretch-out-operation
5) Stretch-in-operation
6) Hereof traction supply
7) Incl. steam supply
BWR: Boiling
Water Reactor
PWR: Pressurised Water
Reactor
Source: VGB
News
atw Vol. 66 (2021) | Issue 2 ı March
72
Operating Results December 2020
Plant name Country Nominal
capacity
Type
gross
[MW]
net
[MW]
Operating
time
generator
[h]
Energy generated, gross
[MWh]
Month Year Since
commissioning
Time availability
[%]
Energy availability
[%] *) Energy utilisation
[%] *)
Month Year Month Year Month Year
NEWS
OL1 Olkiluoto BWR FI 910 880 744 688 814 7 569 248 277 034 717 100.00 95.52 99.80 93.73 100.63 93.66
OL2 Olkiluoto BWR FI 910 880 517 466 356 7 538 637 266 902 722 69.42 94.36 67.82 93.82 68.13 93.29
KCB Borssele PWR NL 512 484 744 377 512 4 087 363 172 068 797 99.43 92.22 99.42 91.65 99.24 90.92
KKB 1 Beznau 3,7) PWR CH 380 365 462 176 487 2 902 566 133 211 386 62.10 87.22 61.50 87.02 62.12 86.85
KKB 2 Beznau 3,7) PWR CH 380 365 456 172 826 3 079 518 140 376 301 61.29 93.07 60.71 92.84 60.82 92.20
KKG Gösgen 7) PWR CH 1060 1010 742 782 632 8 770 354 330 886 589 99.73 95.16 98.34 94.52 99.24 94.19
CNT-I Trillo PWR ES 1066 1003 744 786 642 8 275 822 264 023 848 100.00 90.86 99.95 90.39 98.67 87.73
Dukovany B1 PWR CZ 500 473 0 0 3 760 255 119 644 439 100.00 95.22 0 86.67 0 85.62
Dukovany B2 PWR CZ 500 473 744 361 218 3 568 596 114 611 914 100.00 83.28 96.89 82.80 97.10 81.25
Dukovany B3 PWR CZ 500 473 744 365 065 3 108 821 113 360 557 100.00 73.47 100.00 72.51 98.14 70.78
Dukovany B4 PWR CZ 500 473 744 370 109 3 858 944 114 565 901 100.00 88.57 100.00 88.53 99.49 87.86
Temelin B1 PWR CZ 1080 1030 744 809 835 7 656 477 129 571 290 100.00 80.82 99.99 80.12 100.60 80.57
Temelin B2 PWR CZ 1080 1030 744 819 703 8 106 286 125 588 904 100.00 84.22 100.00 84.03 101.45 85.24
Doel 1 PWR BE 454 433 744 354 288 2 277 781 140 013 841 100.00 56.31 99.98 55.81 102.17 55.57
Doel 2 PWR BE 454 433 744 350 890 2 274 595 138 610 065 100.00 56.96 99.98 56.73 100.80 55.91
Doel 3 PWR BE 1056 1006 744 803 867 8 100 661 271 212 311 100.00 87.60 100.00 87.22 101.74 86.84
Doel 4 PWR BE 1084 1033 744 815 272 7 721 715 277 359 990 100.00 81.36 100.00 80.61 99.62 79.74
Tihange 1 2) PWR BE 1009 962 434 319 552 319 552 307 866 975 58.34 4.94 42.14 3.57 42.45 3.60
Tihange 2 2) PWR BE 1055 1008 0 0 7 649 298 265 703 817 0 84.22 0 83.88 0 83.28
Tihange 3 PWR BE 1089 1038 744 806 734 6 091 082 286 653 659 100.00 64.73 99.97 64.08 100.15 64.03
Plant name
Type
Nominal
capacity
gross
[MW]
net
[MW]
Operating
time
generator
[h]
Energy generated, gross
[MWh]
Time availability
[%]
Energy availability
[%] *) Energy utilisation
[%] *)
Month Year Since Month Year Month Year Month Year
commissioning
KBR Brokdorf DWR 1480 1410 744 983 019 10 542 306 371 263 329 100.00 90.72 98.77 86.27 89.03 80.86
KKE Emsland DWR 1406 1335 744 1 042 827 11 410 500 369 010 701 100.00 93.84 99.97 93.76 99.80 92.41
KWG Grohnde DWR 1430 1360 744 1 027 773 10 485 503 398 760 349 100.00 94.69 100.00 94.47 96.11 82.95
KRB C Gundremmingen SWR 1344 1288 741 976 951 9 154 214 350 477 766 99.62 79.38 96.90 77.71 97.29 76.99
KKI-2 Isar DWR 1485 1410 744 1 096 623 11 666 574 377 429 043 100.00 93.16 100.00 92.99 99.01 89.06
GKN-II Neckarwestheim DWR 1400 1310 744 1 038 000 11 113 300 351 351 544 100.00 92.68 100.00 92.61 99.92 90.52
*) Net-based values
(Czech and Swiss nuclear
power plants
gross-based)
1) Refueling
2) Inspection
3) Repair
4) Stretch-out-operation
5) Stretch-in-operation
6) Hereof traction supply
7) Incl. steam supply
BWR: Boiling
Water Reactor
PWR: Pressurised Water
Reactor
Source: VGB
use 3D- printers, to make crowns from
advanced materials.
A 3D-printer is not quite a “Star
Trek” replicator, but sometimes it
seems close: in industrial versions of
3D-printing, a computer powers a
laser or electron beam welder or other
energy device to fuse a powder into a
precise shape, layer by layer.
3D-printing has huge advantages.
It allows for precisely formed parts
that are more complex than could be
made by casting, molding or even
machining. A part can be 3D-printed
in one continuous form, rather than
assembled from multiple pieces. It’s
like how the advent of plastics decades
ago allowed a single, complicated part
to replace many that used to be fitted
together from metal or wood.
More Nuclear Plants Are Using
3D-Printing to Do Their Jobs Better.
3D-printing is coming to nuclear
energy in a big way – both for plants
running now and the more advanced
reactors moving from the drawing
boards towards deployment.
The Tennessee Valley Authority’s
Browns Ferry plant will load fuel
assemblies this spring with four
3D-printed parts, made of stainless
steel, fabricated by Framatome. This
follows on the progress made last
spring when Westinghouse Electric Co.
partnered with Exelon Corp.’s Byron
plant to deploy another 3D-printed
device, also within the fuel assembly.
Framatome, and many others in the
nuclear industry, are already working
on testing and qualification efforts to
deploy more complex parts.
“There is a tremendous opportunity
for savings,” said John Strumpell,
manager of U.S. fuel research and
development at Framatome. These
savings can make nuclear energy
more cost-competitive, speeding the
transition away from fossil fuels.
Strumpell and others say that advanced
reactor manufacturers are
eyeing 3D-printing as a way to try out
designs quickly, and then rework them
as needed, shortening development
time and speeding their deployment to
help reduce carbon emissions. This
approach does more than just save
time, too, as some new metal alloys
developed for advanced reactors are
stronger if they are fabricated though
3D-printing than if they are produced
through conventional casting.
In an ambitious plan to integrate
advanced manufacturing with new
nuclear technology, the U.S. Department
of Energy’s Oak Ridge National
Laboratory is planning to build an
entire reactor core with 3D-printing
by 2023.
| www.nei.org (203500822)
News
atw Vol. 66 (2021) | Issue 2 ı March
JET prepares for powergenerating
fusion tests
(ipp-mpg) Plasma experiments that
generate fusion energy are planned
for 2021 at the Joint European Torus
JET, the world's largest fusion device
at Culham/UK. Scientists of Max
Planck Institute for Plasma Physics
(IPP) at Garching have contributed
intensively to the preparations. Today,
JET is the only device that can experiment
with the fuel of a future fusion
power plant.
In the first deuterium-tritium
campaign in 1991, JET succeeded in
releasing energy through nuclear
fusion for the first time in the history
of fusion research. For a duration of
two seconds, the plasma delivered a
fusion power of 1.8 megawatts.
Subsequently, throughout the year
2020, under the changed wall conditions
extensive work was carried out
with plasmas of deuterium to develop
the appropriate plasma scenarios for
the third deuterium-tritium campaign.
The group of about one hundred scientists
responsible for this perfecting of
operating modes was headed by Dr.
Jörg Hobirk and Dr. Athina Kappatou
from IPP and two other researchers
from fusion laboratories in Belgium
and the UK. The results – stable
high-power plasmas in deuterium for
about five seconds – give confidence
for the coming tritium operation.
The main aim of the third deuterium-tritium
campaign is to obtain data
for preparing experiments with the
ITER test reactor. “These investigations
are of great importance”, states
Jörg Hobirk, “because the previous
JET values, which are used in preparation
of the ITER experiments, were
not achieved with an ITER-like metal
wall, but with a carbon wall.”
Experiments will start in pure
tritium. Although little energy will be
released, “this offers the unique
opportunity to compare the properties
of tritium and deuterium plasmas and
to study the influence of the isotope
effect on the plasma behaviour, for
example on the turbulence in the
plasma or the density and temperature
profiles”, says Jörg Hobirk. After
careful evaluation, the third and final
deuterium-tritium campaign will start
at JET in the second half of the year.
| www.ipp.mpg.de
Uranium
Prize range: Spot market [USD*/lb(US) U 3O 8]
140.00
120.00
100.00
80.00
60.00
40.00
20.00
0.00
1980
Jan. 2009
Yearly average prices in real USD, base: US prices (1982 to1984) *
Jan. 2010
1985
Jan. 2011
1990
Jan. 2012
Jan. 2013
* Actual nominal USD prices, not real prices referring to a base year. Year
Market data
(All information is supplied without
guarantee.)
Nuclear Fuel Supply
Market Data
Information in current (nominal)
U.S.-$. No inflation adjustment of
prices on a base year. Separative work
data for the formerly “secondary
market”. Uranium prices [US-$/lb
U 3 O 8 ; 1 lb = 453.53 g; 1 lb U 3 O 8 =
0.385 kg U]. Conversion prices [US-$/
kg U], Separative work [US-$/SWU
(Separative work unit)].
2017
p Uranium: 19.25–26.50
p Conversion: 4.50–6.75
p Separative work: 39.00–50.00
2018
p Uranium: 21.75–29.20
p Conversion: 6.00–14.50
p Separative work: 34.00–42.00
2019
January to June 2019
p Uranium: 23.90–29.10
p Conversion: 13.50–18.00
p Separative work: 41.00–49.00
July to December 2019
p Uranium: 24.50–26.25
p Conversion: 18.00–23.00
p Separative work: 47.00–52.00
2020
January to March 2020
p Uranium: 24.10–27.40
p Conversion: 21.50–23.50
p Separative work: 45.00–53.00
1995
Jan. 2014
2000
Jan. 2015
Jan. 2016
2005
Jan. 2017
) 1
2010
Jan. 2018
Jan. 2019
2015
Jan. 2020
2020
Year
* Actual nominal USD prices, not real prices referring to a base year. Year
Sources: Energy Intelligence, Nukem; Bild/Figure: atw 2020
* Actual nominal USD prices, not real prices referring to a base year. Sources: Energy Intelligence, Nukem; Bild/Figure: atw 2021
| Uranium spot market prices from 1980 to 2020 and from 2009 to 2020. The price range is shown.
In years with U.S. trade restrictions the unrestricted uranium spot market price is shown.
Separative work: Spot market price range [USD*/kg UTA]
Conversion: Spot conversion price range [USD*/kgU]
180.00
26.00
) 1 ) 1
160.00
140.00
120.00
100.00
80.00
60.00
40.00
20.00
0.00
Jan. 2021
Sources: Energy Intelligence, Nukem; Bild/Figure: atw 2020
Uranium prize range: Spot market [USD*/lb(US) U 3O 8]
140.00
) 1
120.00
100.00
80.00
60.00
40.00
20.00
0.00
24.00
22.00
20.00
18.00
16.00
14.00
12.00
10.00
Jan. 2009
8.00
6.00
4.00
2.00
0.00
Jan. 2009
Jan. 2010
Jan. 2010
Jan. 2011
Jan. 2011
Jan. 2012
Jan. 2012
Jan. 2013
Jan. 2013
April 2020
p Uranium: 27.50–34.00
p Conversion: 21.50–23.50
p Separative work: 45.00–52.00
May 2020
p Uranium: 33.50–34.50
p Conversion: 21.50–23.50
p Separative work: 48.00–52.00
June 2020
p Uranium: 33.00–33.50
p Conversion: 21.50–23.50
p Separative work: 49.00–52.00
July 2020
p Uranium: 32.50–33.20
p Conversion: 21.50–23.50
p Separative work: 50.50–53.50
August 2020
p Uranium: 30.50–32.25
p Conversion: 21.50–23.50
p Separative work: 51.00–54.00
September 2020
p Uranium: 29.90–30.75
p Conversion: 21.00–22.00
p Separative work: 51.00–54.00
October 2020
p Uranium: 28.90–30.20
p Conversion: 21.00–22.00
p Separative work: 51.00–53.00
November 2020
p Uranium: 28.75–30.25
p Conversion: 19.00–22.00
p Separative work: 51.00–53.00
December 2020
p Uranium: 29.50–30.40
p Conversion: 19.00–22.00
p Separative work: 51.00–53.00
| Source: Energy Intelligence
www.energyintel.com
Jan. 2014
Jan. 2014
* Actual nominal USD prices, not real prices referring to a base year. Year
Jan. 2015
Jan. 2015
Jan. 2016
Jan. 2016
Jan. 2017
Jan. 2017
Jan. 2018
Jan. 2018
Jan. 2019
Jan. 2019
Jan. 2020
Jan. 2020
Jan. 2021
Sources: Energy Intelligence, Nukem; Bild/Figure: atw 2020
| Separative work and conversion market price ranges from 2009 to 2020. The price range is shown.
)1
In December 2009 Energy Intelligence changed the method of calculation for spot market prices. The change results in virtual price leaps.
* Actual nominal USD prices, not real prices referring to a base year | Sources: Energy Intelligence, Nukem; Bilder/Figures: atw 2020
Jan. 2021
73
NEWS
News
atw Vol. 66 (2021) | Issue 2 ı March
74
Biden Includes Nuclear in his Climate Toolkit –
But Can he Build Back Better on Waste Policy?
NUCLEAR TODAY
John Shepherd
is editor-in-chief
of the online publication
New Energy 360 &
WorldBatteryNews.com
Sources:
US nuclear data
https://bit.ly/3szkceF
Biden climate
change plan
https://bit.ly/3oTw5Kj
Bulletin of the
Atomic Scientists
https://bit.ly/3ikET9z
As I write, Joe Biden was preparing to be sworn in as the next US president following the tumultuous period that
followed his election in November. But what might this turning of a page in history mean for the next chapter of nuclear
power? On the face of it, Biden’s election could be a promising, fresh start for the US, as it pursues a new era of nuclear
innovation.
According to a raft of clean energy policy proposals already
unveiled by Biden and his vice-president, Kamala Harris,
the new administration will establish “an enforcement
mechanism to achieve net-zero emissions no later than
2050” and that will include a renewed focus on nuclear
energy.
Of particular interest is the specific mention of pursuing
nuclear innovation in the form of small modular reactors
(SMRs). Biden has committed to establishing ‘ARPA-C’ as
an advanced research projects agency focused on climate.
The initiative, according to the Biden plan, “will target
affordable, game-changing technologies to help America
achieve our 100 % clean energy target”, including development
of SMRs “at half the construction cost of today’s
reactors”.
In another promising move, Biden has nominated
former Michigan state governor, Jennifer Granholm, to
serve as the head of the US Department of Energy.
Granholm’s nomination has been welcomed by the
president and CEO of the US Nuclear Energy Institute
(NEI), Maria Korsnick, who said Granholm had seen “firsthand
the hard work and dedication of thousands of highlyskilled
workers responsible for the majority of the state’s
carbon-free electricity produced by Michigan’s three
nuclear power plants”.
“We are committed to working with the incoming
energy secretary to build a carbon-free future for America
that includes and appropriately values nuclear energy,
alongside other carbon-free energy sources like wind and
solar,” Korsnick said.
“This means a continuation of programmes essential
to clean energy job creation and the deployment of
more carbon-free technologies – like the programmes
to demonstrate SMRs and other advanced reactors, the
Versatile Test Reactor and other R&D efforts.”
According to data from the NEI, the US has 94 reactor
units across 55 sites. In addition, the Biden administration
takes the helm of a country where nuclear power generated
809.4 billion kilowatt-hours (kWh) of electricity in 2019 –
with a 93.4 % capacity factor in that same year. Critically,
for the new administration’s climate agenda, two US
nuclear power plants that were responsible for more than
11.7bn kWh of carbon-free electricity were prematurely
retired in 2019.
And, as the NEI explains, carbon emissions avoided
by the US nuclear industry in 2019 (505.8 million metric
tonnes) was equivalent to taking nearly 110m cars off the
road.
Nuclear energy enjoys bipartisan support in the US, so
the incoming administration is pushing at an open door in
seeking to deploy nuclear and a range of clean-energy
technologies to combat climate change and encourage
investment in high-paying jobs throughout the nuclear
supply chain.
In the final weeks of 2020, Congress voted to approve
$1.5bn (about €1.2bn) for nuclear energy programmes.
The NEI said funding for advanced reactor
demonstrations, including small modular reactors and
micro-reactors, would “keep America competitive in this
strategic sector”.
However, the new administration will need to spell out
the government’s direction of travel in terms of managing
spent fuel and waste?
Biden’s clean energy plan includes a curious turn of
phrase. It says the new administration will “identify the
future of nuclear energy”.
The plan adds: “To address the climate emergency
threatening our communities, economy, and national
security, we must look at all low- and zero-carbon technologies.
That’s why Biden will support a research agenda
through ARPA-C to look at issues, ranging from cost to
safety to waste disposal systems, that remain an ongoing
challenge with nuclear power today.”
Industry leaders and others will need to work quickly to
ascertain exactly what is meant by that to move forward
with certainty. If the new administration is hinting at a
nuclear policy review – which the wording suggests –
it will be imperative to ensure that years of political feetdragging
and indecision on waste disposal is not further