atw - International Journal for Nuclear Power | 02.2021

nucmag.com

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


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


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


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”


16 Quo Vadis, Grid Stability?

Challenges Increase as Generation Portfolio Changes



30 From Fossil Fuel Super Power to Net Zero –

Can Australia Deliver an Orderly Energy Transition?



46 The Other End of the Rainbow:

Nuclear Plant End-of-Life Strategies


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


Contents


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


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?


8

CALENDAR

Calendar

2021

Virtual Conference 08.03. – 12.03.2021

WM2021 – Waste Management Symposia.

X-CD Technologies, www.wmsym.org


EURAD 1 st Annual Event.

www.ejp-eurad.eu


ETRAP – 7 th International Conference on

Education and Training in Radiation Protection.

FuseNet, www.etrap.net


INBP – Indian Nuclear Business Platform.

NBP, www.nuclearbusiness-platform.com


World Nuclear Fuel Cycle. WNA World Nuclear

Association, www.wnfc-event.com


AFNBP – African Nuclear Business Platform.

NBP, www.nuclearbusiness-platform.com


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


FEC 2020 – 28 th IAEA Fusion Energy Conference.

Nice, France, IAEA, www.iaea.org


Nuclear Power Plants IV. Expo & VIII. Summit

(NPPES). Istanbul, Turkey, INPPES Expo,

www.nuclearpowerplantsexpo.com


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


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


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


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

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2011

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| 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


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



| 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




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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



“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


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



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



16

SERIAL | MAJOR TRENDS IN ENERGY POLICY AND NUCLEAR POWER


Challenges Increase as Generation Portfolio Changes


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.


Quo Vadis, Grid Stability? Challenges Increase as Generation Portfolio Changes ı Kai Kosowski and Frank Diercks


| 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.





| 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).




| 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.


11 Not publicly accessible.





| 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.




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


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 .





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.




| 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]).


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.





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.




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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zur Systemrelevanz ausweisung des Kraftwerkblocks Staudinger 4. Bonn, 14.09.2018

https://www.bundesnetzagentur.de/SharedDocs/Downloads/DE/Sachgebiete/Energie/

Unternehmen_Institutionen/Versorgungssicherheit/Erzeugungskapazitaeten/systemrelevante_

KW/Tennet_Staudinger4_14_09_2018.pdf


zur Systemrelevanz ausweisung des Kraftwerkblocks 7 des Großkraftwerks Mannheim. Bonn,



systemrelevante_KW/Transnet_Mannheim03_08_2020.pdf

[53] Wulff, F. : Results of first tendering process to reduce the production of electricity from coal.

Bundesnetzagentur. Press Release, December 1, 2020. https://www.bundesnetzagentur.de/

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Weekly Newspaper. Article. Axel Springer publishing group. Number 36. 06.09.2020.

https://www.welt.de/regionales/hamburg/article215118872/Energieversorgung-Wie-soll-dasgehen-ohne-das-Kraftwerk-Moorburg.html

[N2] Zimmermann, O.: Kraftwerk Moorburg soll stillgelegt werden. Elbe Wochenblatt.

Weekly Newspaper. Elbe Wochenblatt Verlagsgesellschaft mbH & Co.KG. 08.09.2020.

https://www.elbe-wochenblatt.de/2020/09/08/kraftwerk-moorburg-soll-stillgelegt-werden/

[N3] Stuttgarter Zeitung. Red/lsw/dpa: Großkraftwerk Mannheim. Systemrelevant – Kohlekraftwerk

darf Block 7 noch nicht vom Netz nehmen. Daily Newspaper. Stuttgarter Zeitung Verlagsgesellschaft

mbH. 07.09.2020. https://www.stuttgarter- zeitung.de/inhalt.grosskraftwerkmannheim-systemrelevant-kohlekraftwerk-darf-block-7-noch-nicht-vom-netz-nehmen.

e02dcb17-f186-4c43-a560-88fc7f62c13b.html

[N4] Geiger, M.: Block 7 des Mannheimer Großkraftwerks bleibt vorerst am Netz. Mannheimer

Morgen. Daily Newspaper. Mediengruppe Dr. Haas GmbH. 07.09.2020.

https://www.morgenweb.de/mannheimer-morgen_artikel,-gkm-block-7-des-mannheimergrosskraftwerks-bleibt-vorerst-am-netz-_arid,1684152.html

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Anstalt des öffent lichen Rechts, 07.09.2020. https://www.br.de/nachrichten/wirtschaft/

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[N6] Bayerische Staatszeitung: Der Irrsinn von Irsching. Daily Newspaper. Article. 29.03.2019

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artikel/der-irrsinn-von-irsching.html

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[N8] Sommerfeldt, N., Zschäpitz, H.: Ökostromschwemme. Der Preis für Strom ist negativ – und Verbraucher

zahlen Rekord rechnungen. Welt. Daily Newspaper. Article. Axel Springer publishing

group. 07.07.2020. https://www.welt.de/wirtschaft/plus211134619/Negative-Strompreise-Die-

Verbraucher-zahlen-trotzdem-so-viel-wie-nie.html

[N9] Poppe, M.: Negative Strompreise. Deutschland verschenkt Strom-Millionen an Frankreich – auf

Kosten der Verbraucher. Focus Online. Hubert Burda Media. 24.04.2019. https://www.focus.de/

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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.




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


Challenges and Perspectives for Long-Term Operation in Switzerland ı Natalia Amosova


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




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.


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





From Fossil Fuel Super Power to

Net Zero – Can Australia Deliver

an Orderly Energy Transition?


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


From Fossil Fuel Super Power to Net Zero – Can Australia Deliver an Orderly Energy Transition? ı Dayne Eckermann, Oscar Archer and Ben Heard


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


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





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




| 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


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




State Goal Support mechanisms


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




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


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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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.




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.


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


Extending Nuclear Plant Licenses to 80 Years – Essential to Achieve a Reliable Future Energy Mix ı James Conca


Nuclear Plant Unit Capacity Operational Life Unit Capacity Operational Life


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


Extending Nuclear Plant Licenses to 80 Years – Essential to Achieve a Reliable Future Energy Mix ı James Conca


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


11 http://www.platts.com/commodity/electric-power


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


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.

Site Spotlight

Beznau Nuclear Power Plant – Decades of Safe, Environmentally Friendly Power Generation


SITE SPOTLIGHT

EDITORIAL 41

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

Site Spotlight



SITE SPOTLIGHT

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

Site Spotlight



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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SITE SPOTLIGHT

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



46

DECOMMISSIONING AND WASTE MANAGEMENT

The Other End of the Rainbow:

Nuclear Plant End-of-Life Strategies


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.


The Other End of the Rainbow: Nuclear Plant End-of-Life Strategies ı Edward Kee, Ruediger Koenig and Geoff Bauer


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.





| 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.




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


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





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.




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


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.





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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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






| 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




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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


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.





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


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


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.




Ground Control and the Principle of

Minimizing Radiological Exposure as Key

Drivers for the Recovery of Radioactive

Waste Out of the Asse II Mine


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].



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



| 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.




| 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).


| 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].





| 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.




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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





| 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].




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



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



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.





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


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


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


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


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.





| 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.




| 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.





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


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


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]


[MWh]

Time availability

[%]

Energy availability


[%] *)

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


72

Operating Results December 2020

Plant name Country Nominal

capacity

Type

gross

[MW]

net

[MW]

Operating

time

generator

[h]


[MWh]

Month Year Since

commissioning

Time availability

[%]

Energy availability


[%] *)

Month Year Month Year Month Year

NEWS



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]


[MWh]

Time availability

[%]

Energy availability


[%] *)

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


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



2019

January to June 2019

p Uranium: 23.90–29.10



July to December 2019

p Uranium: 24.50–26.25



2020

January to March 2020

p Uranium: 24.10–27.40



1995

Jan. 2014

2000

Jan. 2015

Jan. 2016

2005

Jan. 2017

) 1

2010

Jan. 2018

Jan. 2019

2015

Jan. 2020

2020

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


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



May 2020

p Uranium: 33.50–34.50



June 2020

p Uranium: 33.00–33.50



July 2020

p Uranium: 32.50–33.20



August 2020

p Uranium: 30.50–32.25



September 2020

p Uranium: 29.90–30.75



October 2020

p Uranium: 28.90–30.20



November 2020

p Uranium: 28.75–30.25



December 2020

p Uranium: 29.50–30.40



| Source: Energy Intelligence

www.energyintel.com

Jan. 2014

Jan. 2014


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


| 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


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

atw - International Journal for Nuclear Power | 02.2021

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